Going Open Access

In the mandatory open-access era (1985–), Transwestern and Northern Natural led the transition from gas merchants (buyers and sellers) to fee-based transporters of supply owned by others. Incurred take-or-pay costs from exiting the merchant function were mitigated by legal terminations (force majeure clauses), early settlements, and partial recoupment from customers in regulated rates. But the remaining write-off was well spent in Enron’s case because two profit centers replaced one. Enron’s interstate pipelines made margins on transportation, and Enron Gas Marketing (under its evolving names) made money buying and selling gas and offering ancillary services.

Florida Gas Transmission (operated and 50 percent owned by Enron) and Northern Border (operated and 35 percent owned by Enron) were among the last interstates to accept open access under the provisions of FERC Order No. 436. As with the early adopters, the reason was pecuniary, not philosophic.

Running at full capacity as the sole provider to Florida and with customer contracts that needed to reach their full term, FGT entered the new world in August 1990. Northern Border, a cost-of-service pipeline fully subscribed by producer shippers, continued to operate as before.

“At the end of fiscal year 1990,” reported FERC, “all 23 of the major pipelines held blanket certificates and provided non-discriminatory access to the gas transportation market.” But this was under FERC Order No. 436 and did not include Northern Border. The final restructuring rule, FERC Order No. 636 (1992) required new comparability rules and new rate designs to complete the transition to open access.

“The challenge is to take the broad framework and flexibility FERC has given us in Order 636 and adapt the system to fit the needs of customers,” Ron Burns explained to the Oil & Gas Journal. “[A] cookie cutter approach will not work.” Transwestern, operationally the simplest interstate of Enron’s four, was approved by FERC in 1992. The next year, Northern Natural and FGT also converted to final open access. Northern Border Pipeline, which went public in 1993 as a master limited partnership (MLP), received final approval under Order No. 636 last, in October 1993.

“Full implementation of the Federal Energy Regulatory Commission’s (FERC) Order 636 and the successful settlement of all significant regulatory issues on our interstate pipelines during 1993 should provide a constant and reliable stream of cash flow over the next several years from our largest single earnings contributor,” Enron told investors.⁸ Automation and modernization, too, substituting profitable rate base for passthrough labor costs, put “Enron’s interstate pipelines … in optimum shape from both an operational and regulatory perspective.”

Operational Order

The role of interstate pipelines as transporter, not merchant, came to a head at a trade association meeting in early 1990. The instigator of change was Ken Lay; the result was new protocol and industry standards regarding operational flow orders and operational balance agreements that became standard by 1992. Therein lies a story.

Few knew that Ken Lay had a temper. Patience and pleasantry were his public persona. But when he lost his cool, it was something to behold. For Lay had a bigger monkey on his back than most realized or understood. His psyche carried memories of his dirt-poor past—including the business failures of his father, Omer. The smart, energetic, and über-productive Lay had gone through life accommodating less talented, more moneyed colleagues. Lay had always worked his rear off to have a jingle in his pocket. He was well coordinated but physically short, too, which held him back in sports competition against some of his more statured opponents.

It was not easy being in such a hurry yet having to deal with just about everyone else’s slower pace. But Ken worked (and prayed) hard at patience and got good at leading others to perform so he could succeed that much more.

When his inner ego was violated, as when his business was being hurt unjustly, the invectives could fly. Lay had mixed it up with Selby Sullivan during the 1970s back at Florida Gas Company, a story told in chapter 8 of Bradley, Edison to Enron. John Wing could really get his goat, too. But if someone was nice and innocent, Ken found patience. After all, he—Ken Lay—was the underdog too, in a different sort of way, and he empathized.

But it was an unforgettable moment when a furious Ken Lay walked into a January 1990 board meeting of the Interstate Natural Gas Association of America (INGAA), the interstate pipeline trade association. Staring down his fellow CEOs one by one, he yelled: “You f—ing stole my gas.” “You owe me gas.” Around the table of pipeline heads Lay went.

A severe cold snap had badly tested the interstate gas system just weeks before. The interstates were borrowing, and even shorting, gas to each other in the frantic search to meet peak demand. Enron, which had upgraded its gas operations for the open-access world and had the widest reach of any one company, found itself on the short end of many transactions. Formal operational controls were not yet in place. It was relationships and handshakes where Enron unwittingly became the bank.

“Ken Lay’s quite forceful language behind closed doors was arguably the beginning of the protocols operational flow orders and operational balance agreements that became the industry norm by 1992,” remembers Skip Horvath, INGAA’s vice president of analysis. The fire lit that day would be a catalyst for new best practices and better performance in the winter of 1991–92 and beyond.

The computerization of gas logistics in a nonintegrated industry made information technology (IT) a top expense at Enron, as at other companies. For pipelines, unbundled transportation was more complicated than it was before, when they acted as bundled gas merchants; for national marketing companies such as Enron Gas Marketing, the complexity was beyond what could have been coordinated in the days of manually handled information.

Expensive mistakes with IT resulted in a master contract with Ross Perot’s EDS in 1988. Enron’s IT expense of $70 million in 1987 was followed by a 10-year outsourcing contract that began at $16 million and was set to escalate to $140 million in year 10.

As the Enron-EDS alliance matured, a number of disputes arose that required a rethink from Enron’s side to improve IT service at a more manageable cost. In mid-1991, an Information Services Team was formed with all the units represented to develop new guidelines, improve coordination, and centralize dispute resolution.

Four years into the agreement, a major restructuring of the contract was announced to “improve the flexibility of both organizations to deal with new and evolving technology.” Three years were added to the contract (through 2001), and Enron subsidiaries were assigned a part of the cost and instructed to manage and improve their IT function. Some services were unbundled to allow more tailored provision per unit. Performance bonuses and penalties were built into the contract too.

In a separate transaction, EDS acquired 3.5 million new shares of ENE to reduce Enron’s debt-to-capital ratio by two percentage points. The transaction was expected to be nondilutive to earnings with better efficiencies and aligned incentives.

The new contract was the work of Rich Kinder from Enron’s side, given that the EDS-Enron alliance was a key variable on the cost side of the business equation. IT was that important in the new natural gas—and later, electricity—world.

Back to Decentralization

In late 1992, Enron Pipeline and Gas Liquids Group was formed to house the regulated pipelines, as well as Producer Field Services (the newly deregulated feeder pipes from the field to the large-diameter interstates); Clean Fuels (MTBE and methanol plants purchased from Tenneco); and Enron Liquids Pipeline. Ron Burns was chairman; Stan Horton was named president of the pipeline division in addition to his position of president, Northern Natural Gas.

Reporting to Horton were Terry Thorn, president of Transwestern; Bill Allison, president of Citrus and FGT; and Larry DeRoin, president of Northern Plains. The heads of the still-centralized accounting, finance, and legal functions reported to Horton as well.⁹ Intrastate Houston Pipe Line remained in Enron Gas Services as part of the unregulated merchant-gas side, as would Louisiana Resources Company (LRC), an intrastate purchased in early 1993.

Commercial-side decentralization was the major thrust of the reorganization. One size did not fit all when it came to meeting specific customer needs. Each president had a lot of customer touch to do that was lost in the previous organizational structure, not only at the terminus of the pipeline but also at the source. Producers were customers; without gas, there would be no sales at the other end.

Regulation also limited economies of scale for Enron’s hub-and-spoke system. The network synergies that Lay envisioned for his adjoining coast-to-coast, border-to-border pipelines were neutralized by FERC pipeline-specific regulation, not to mention nondiscriminatory open access. This could have been anticipated. Still, some functions were centralized, and best practices and standardization were achieved by rotating employees between pipelines.

Transwestern: Expedited Certification

With Enron’s interstates in expansion mode, timely FERC authorization was crucial for the parent to retire debt and increase profits. Yet getting Section 7(c) authority under the Natural Gas Act to enter a market or expand an existing pipeline was a time-honored forum for delay by rival projects and fuels. Back in the 1950s, Florida Gas Transmission narrowly overcame fuel-oil interests to receive a certificate to build to the Sunshine State.¹⁰ Northern Natural Gas Pipeline beat coal interests for its federal certificate a quarter-century before. Receiving its certificate in 1959 after only 15 months, Transwestern had an easier time in gas-needy California.

In June 1990, Transwestern applied to FERC for a 340 MMcf/d, $160 million mainline expansion to (once again) gas-short California, coupled with a 520 MMcf/d, $90 million lateral expansion to receive surging supplies of (tax credit–aided) coal-seam gas from New Mexico’s San Juan Basin.¹¹ With Transwestern’s 18-month construction schedule and a full customer subscription, Enron wanted the project’s double-digit incremental profits as soon as possible.

When Iraq invaded Kuwait two months later, making oil geopolitics a national security issue, Ken Lay went into overdrive with a gas-for-oil substitution argument to speed Transwestern’s approval. FERC and the US Department of Energy, indeed, were already on record favoring expedited pipeline certification to increase gas-on-gas competition and support the cleanest fossil fuel.

Transwestern’s expansion stood to displace as much as 55,000 daily barrels of oil imports. (California power plants, under periodic gas curtailments, were reluctantly burning fuel oil.) Industry-wide, Enron put the gas-for-oil substitution opportunity between 250,000 and 500,000 barrels of imported oil per day.¹²

In September 1990, Transwestern reapplied to FERC for an expedited certificate. “Providing this nation with stable supplies of domestically produced, environmentally safe fuel has never … been more critical,” Transwestern’s filing stated. Terry Thorn quipped to the trade press: “We can save the country from Iraq and El Paso [Natural Gas] with just one filing.” Transwestern’s president was like that: a bit irreverent to go along with his business and professorial sides.

The new plan resulted in a preliminary certificate whereby Transwestern could embark on preconstruction business matters, while hiring its own environmental firm to remediate the right-of-way for artifacts pursuant to the Historic Preservation Act. With this head start, the full certificate resulted in “a modern-day record” of 18 months between federal application and gas delivery (September 1990–February 1992).

Chopping months off the process for a project with an IBIT of $40 million per year added millions of dollars to Enron’s 1992 bottom line. Transwestern, the little pipeline that could, was the last to apply for FERC certification and the first to provide new capacity to gas-short California.¹³

Besting Oil in Florida

Enron’s grand plan to ride economic growth in California and Florida encountered an unexpected problem when oil prices precipitously fell in 1986. Discounting was necessary to regain or retain markets for gas in dual-fuel power plants. But in the case of Florida, where Florida Power & Light (FPL) was the world’s largest residual fuel oil buyer for electrical generation, a complicated 15-year gas contract by Enron priced to resid turned problematic. Throughput on Florida Gas Transmission hung in the balance.

In fact, Citrus/Enron was losing several million dollars per month on buying and reselling under the terms of Mark Frevert’s 1985 deal. The tracking account—designed to carry losses forward in low-resid-price months and erase them in months when higher prices for resid prevailed—was not working as planned. Falling demand for resid, for environmental and other reasons, resulted in perennially low prices and delivered-gas price losses for Citrus. And all of it was Enron’s problem, not Sonat’s.

The historic gas-to-resid price ratio had blown up. Monthly losses between $3 million and $7 million had no relief in sight. Consecutive losses that were supposed to trigger contract termination did not quite work as planned either. Enron calculated a $450 million net present liability, requiring a new contract, as well as payments and concessions to FPL. It was a problem one-third that of Enron’s infamous J-Block contract in the United Kingdom to come.¹⁴

The problem contract became one for Enron Gas Services to solve. That job went to Geoff Roberts, formerly of FPL, who had negotiated the deal on the other side of the table from Enron’s Frevert. Roberts assigned Mike McConnell to lead the renegotiation.

As McConnell would later explain in his memoirs, Enron’s number-one corporate goal for 1992 was settled with upside. The large liability was resolved with a $50 million check to the buyer, and the restructured contract actually put Enron in the money as resid prices strengthened. Enron’s brightest, including Vince Kaminski, had done a good job. Roberts’s former colleagues wanted to amend a deal that seemed to go more and more Enron’s way with pricing relationships. The contract also created a mark-to-market profit of $60 million, which got McConnell a nice bonus and promotion to vice president.

Full Utilization

It had been nearly a decade since Ken Lay restructured the old Houston Natural Gas by entering the federally regulated midstream gas market. By 1993, each Enron interstate was transportation only, with arm’s-length affiliate Enron Gas Marketing or nonaffiliated independent marketers buying and selling the (transported) gas. Once-feared operational problems in the transition from purchased supply to received supply proved immaterial. Rich Kinder’s Come to Jesus meeting in 1988 had set the stage for the old-guard pipeliners and new-guard marketers to divide (unbundle) and conquer.

Capacity in 1993 on Enron’s four interstates (including joint-venture Northern Border) was almost 8 Bcf/d, 10 percent greater than in 1990 and just ahead of national market growth. Utilization was at or close to capacity year-round except on Northern Natural, which was built to meet high winter demand (the peak versus the shoulder months). Northern Border’s 25 percent expansion to 1.7 Bcf/d to meet the 1992/93 winter heating season was running at full tilt. Houston Pipe Line, on the other hand, was relatively margin-poor in the oversupplied Texas gas market.¹⁵

On many days, excess capacity on Enron pipelines necessitated discounting below FERC-authorized maximum rates, which were based on depreciated original cost, not replacement costs. Pipeline-to-pipeline rivalry characterized every market except that of Florida Gas Transmission, which was the sole supplier to the state. But Enron’s former head of pipeline operations, E. J. Burgin, was knocking on doors to get contracts to build a second pipeline to the Sunshine State, a proposed 800 MMcf/d, $1.4 billion project cosponsored by United Pipeline and Coastal Gas Transmission.

“Despite the fact that interstate pipelines still are regulated and the FERC will set minimum and maximum rates for each of our unbundled services,” Stan Horton explained, “we’re finding that competition is determining what we can actually charge.” Being the low-cost provider was essential, the head of Enron’s interstates explained. “We want to ensure that our customers are not going to leave us to receive service from Natural Gas Pipeline of America, ANR, El Paso, or Sunshine or whomever the competition is.” But being low cost at Enron would not be easy with Ken Lay’s first-class tendencies (a corporate charge to the interstates); Horton could not quite do what Forrest Hoglund could do at Enron Oil & Gas.¹⁶

One of Enron’s goals in the 1991 annual report read: “Abandon strict rate-base mentality and expand pipelines only when economically justified.” Enron’s real world was different from the textbook natural-monopoly model, bringing into question the public interest rationale of the Natural Gas Act of 1938 for public-utility regulation. And so Ken Lay and Enron stumped for lightened regulation with rates, as with entry.

In 1990, Lay floated the idea of a new maximum rate based on “fair value” (such as replacement cost instead of original depreciated cost) to “respond to market forces.” This was how interstate oil pipelines were regulated at FERC, and cost as redefined could meet the cost-based, just-and-reasonable criteria under the Natural Gas Act. This was also the position of INGAA.

The next year, Lay reiterated his plea that pipelines needed extra incentive to go the extra mile via an expanded risk-and-reward frontier.¹⁷ As part of their rate cases, both Northern Natural and FGT filed rate cases proposing incentive rates in 1991. But FERC head Martin Allday (1989–93) put a heavy burden of proof on applicants. Lay could only complain: “It is time FERC stopped talking about incentive rates and started granting them.”

Allday’s predecessor as head of FERC, Martha Hesse (1986–89), had put incentive rate making on the agenda to allow pipelines to keep a greater share of their productivity (efficiency) gains. Invoking a dynamic (versus a static) view of competition, she explained: “I don’t think that there’s any doubt that the extensive regulation of gas from the gathering line to the burner tip is at least partially responsible for the gas industry’s sluggish performance over the last 20 years.” The lure of pure profits (profits higher than FERC-assigned “reasonable” profits) was necessary for Schumpeterian innovation, Hesse explained, describing incentive rates as an “attempt to emulate the life cycle of entrepreneurship.”¹⁸ The industry had transitioned, she said. FERC “has to transition too.”

Hesse gave specific examples of inefficiency. Risky projects might not be built without higher profit potential. Cost-reducing projects beyond the three-year rate-case period might not be done. Rate discounts (below fully allocated cost, the rate maximum) to increase volume would accrue against the pipeline in the next rate case when assigning volumes. Still, the static view of competition, versus the dynamic entrepreneurial view, would be too hard to overcome despite Hesse’s proposal, not to mention Ken Lay’s and Enron’s best efforts, as well as that of the entire interstate pipeline industry.¹⁹

From Teesside to Enron Europe

By 1990, “Iron Lady” Margaret Thatcher had liberalized the United Kingdom’s socialistic electricity sector, which supported the heavily unionized coal sector with an exclusive long-term contract. Market competition was needed to bring down power prices and remove cronyism, as well as demote labor strife. British Gas, a monopoly, also needed competition.

About the same time, discoveries of natural gas in the North Sea created potential competition to coal. Coupled with advances in gas-turbine technology, a new competitive arena was created for private firms, particularly for newcomer Enron with its cogeneration expertise and sense of urgency.

John Wing, under a consulting contract with Enron, got right on it. Ken Lay did too, visiting Thatcher’s energy minister, John Wakeham, to lobby for fast-track approval.

Wakeham found Lay to be “very sensible” and “very determined”—a man who “understood his subject better than perhaps the competition did.” The Energy Secretary (1989–92) welcomed the “nitty-gritty” discussions that “helped to prove that my system of electricity privatization, complete with a competitive market, was moving very substantially in the right direction.”

Permissions would be expedited for the 23-acre, modernistic project. Wakeham himself would have celebrity honors when the Teesside Power Station opened in March 1993. Prince Charles reputedly turned down the opportunity—but not from a lack of Enron effort, including donations to the Prince’s Trust. Ken Lay was that way.

The project began when John Wing and his top lieutenant at the Wing Group, Robert Kelly, ventured to London in 1988 to line up contracts for the world-class project. The project needed commitments for power and steam, gas supply to generate both, and a pipeline to get the offshore gas to the plant.

By year end, a long-term sales agreement was reached with Ralph Hodge of Imperial Chemical Industries (ICI) for all the steam and 700 MW of power. Teesside was home to ICI’s major facility, and ICI joined the project as 10 percent owner. A group of utilities led by Midlands Electricity increased the power commitment to 1,750 MW, with the remaining 125 MW (to 1,875 MW capacity) being discretionary peak output for spot sales.

Gas supply was a major challenge. For the economics to work, a pipeline had to be built at a scale beyond Teesside’s required 150 MMcf/d. The problem was partially solved with the addition of a 7,500 bbl/day gas liquids plant requiring 90 MMcf/d, which resulted in a 15-year, 240 MMcf/d gas contract with a 70 percent take-or-pay clause. Enron committed to a 300 MMcf/d transportation contract with the Central Area Transmission System (CATS) pipeline, a consortium led by the major North Sea producer Amoco (later BP) to move the gas 140 miles to Teesside.

To win his customers, Wing not only offered cheaper power and more power and steam. He also entered into strict completion-date contracts with bonuses and penalties. Enron had upped its ante to finalize the contracts necessary to build the plant.

Before project financing could be secured, Enron self-financed construction—as if it were already the energy major that the project was to help it become. For “six nerve wracking months,” Enron poured $300 million of its precious capital into the project. Wing hired some of the US Army’s top infrastructure managers to speed construction. Thomas White, Larry Izzo, and Lincoln Jones would be part of the Enron story to come.²⁴

Round-the-clock activity, daily 7 a.m. staff meetings, and ferocious Wing management proved barely enough.²⁵ The gas contracts were finalized with just minutes to spare. Plant completion was two days ahead of its April 1, 1993, deadline—a 29-month record for a project of this scope.

Goldman Sachs provided $1.3 billion to take out half of Enron’s interim cost, leaving Houston with a $150 million investment for 50 percent of the $1.2 billion asset. Already, $100 million in-construction profits—earned by Enron Power as builder and operator—had been recorded in 1991 and 1992 to bolster earnings.

“Few outside Enron knew how much risk the company had taken to build Teesside, and afterward, few cared.” The bet-the-company strategy worked; later such moves would not end this way.

The Teesside project was recognized in Enron’s 1990 annual report as the first of “numerous” opportunities for “Enron’s total package concept offering a wide range of coordinated services.” To meet this goal, Enron Europe was formed in mid-1990 to manage all gas activities throughout the continent, whether pipelines, liquids, power plants, and even exploration and production.

“Enron Europe, Ltd., is an integral part of the company’s vision to become the first natural gas major worldwide and will allow Enron to expand all of its core businesses in the international arena,” the 1990 annual report stated. The operations around Teesside were seen as just the beginning for the London-based subsidiary, which was featured on the cover of Enron’s 1991 annual report.

In mid-1992, an agreement in principle was announced with Eastern Generation for a $300 million, 380 MW gas-fired power plant, with construction in 1993. Phase II of Teesside’s liquids plant was planned for 1994. Enron also foresaw a need for gas marketing, all part of an ambitious “mini-Enron” UK plan.²⁶

The United Kingdom’s “dash for gas” in place of dirty coal seemed to be all going Ken Lay’s way. So in March 1993, Enron Europe (now part of Enron International) contracted for 300 MMcf/d of J-Block North Sea gas for 15 years, commencing in 1996. Enron’s purchase commitment was necessary for Conoco/Phillips, British Gas, and Agip to develop the Judy and Joann fields in central North Sea—a billion-dollar proposition. A 300 MMcf/d send-or-pay transmission contract with the Central Area Transmission System (CATS) supported coastal delivery. The enlarged 1.4 Bcf/d system, led by British Gas, Enron’s entrenched rival, needed such shipper certainty to build the line.

But there was a major difference between Enron’s gas-supply commitments of September 1990 and those of March 1993. Neither Eastern Generation nor a second-phase Teesside gas-processing facility was a done deal; both the supply and transmission contracts were speculative. As he had done before (and would do again), Ken Lay made a naked bet that locking up gas supply on the front end would ensure Enron’s preeminence for a grand European strategy.

Riskier still, J-Block gas was purchased at fixed, escalating prices without a market-out clause to protect against falling prices—as if the 1980s US experience could not happen in the UK gas market. This 300 MMcf/d had a 100 percent take-or-pay financial requirement and a minimum physical take of 260 MMcf/d to all but ensure that 95,000 barrels of oil per day (the gas was associated) could be produced. More than a trillion cubic feet of gas was estimated to reside in the Judy and Joann fields in the central North Sea—and Enron wanted all of it.

Enron’s obligations were “firm, extremely firm,” noted Mike McConnell, the Enron employee who later was tasked with fixing the contracts. “It seemed that almost every possible item was against Enron,” he recalled. “Phillips and the original negotiator took such advantage of Enron’s need that they ‘almost punished’ them in negotiations.” He could only conclude: “I was frustrated with the agreements.”

Robert Kelly, head of Enron Europe, who was responsible for J-Block, cited the goal to “become a major competitive supplier of gas in the United Kingdom to electric power stations as well as other customers.” (He also was convinced that gas would become less, not more, plentiful.) Teesside’s 4 percent share of the UK power market left plenty of growth for gas, Ken Lay (and Rich Kinder) believed back home.²⁷ And Enron’s board was not going to buck its golden boy.²⁸

The Eastern Generation deal faded, and a liquids expansion at Teesside was short of customer commitments. Worse, a lot of new North Sea supply that Enron did not anticipate spelled trouble for prices. Neither was this good for Enron Oil & Gas’s purchase of a quarter-interest in four undeveloped North Sea blocks, initially celebrated as “further integrating [our] European activities.”

Enron was dangerously long on gas supply and transportation. J-Block and CATS II would turn into a billion-dollar problem. Only desperate, nimble negotiation and a much stronger Enron could weather this very expensive mistake.²⁹

Transportadora de Gas del Sur (Argentina)

An all-employee memo from Rich Kinder in late 1992 shared the good news: An Enron-led consortium successfully bid for 70 percent ownership of a major natural gas pipeline system and adjacent liquids facility in southern Argentina under a 35-year concession, with an option for 10 more years. As operator and 17.5 percent owner of the plant under a fee agreement, Enron was exporting its capabilities in a second key region after Teesside. As in the United Kingdom, Argentina was newly privatizing, and Enron was first,³⁰ aided by generous government loan guarantees.

In addition to the prospect of providing “immediate earnings” for 1993, Kinder lauded Transportadora de Gas del Sur (TGS) as “consistent with Enron’s vision of becoming the first natural gas major and the most innovative and reliable provider of clean energy worldwide for a better environment.” Natural gas had a 40 percent market share in Argentina, and two-thirds of it was in TGS’s territory.

The approximately $550 million winning bid for 70 percent of the system was $100 million above the sole other offer submitted by Tenneco and below the bottom of the range authorized by Enron management. Kinder and Lay were concerned, even upset, that the offer might fail. But Mike Tucker’s team had researched the opportunity to identify real value but not overvalue. Enron’s 25 percent equity investment, $25 million, would create an equity return near or above 20 percent in its first years, as much or more than Enron’s domestic pipelines.

Argentina was a Third World, populist country disdainful of the ideals and rigor of market capitalism. Anti-American sentiment was prevalent. The country had been “a capitalist wonder during 1860–1914, enjoying phenomenal growth rates and rising prosperity.” But spiraling intervention set in, particularly during the Juan Peron era (1946–55). Government corruption, rent-seeking, hyperinflation, punitive taxation, price controls, nationalism, and nationalization predictably created crises and coups. Foreign debt of $65 billion held by Argentina had enabled much crony socialism.

Crisis can bring fundamental reform. In the early1990s, Carlos Menem, Argentina’s president, embarked on a new policy of privatization and market reliance. Part of this was privatizing state enterprises to reduce annual budget deficits, which were 15 percent of Argentina’s GDP in 1989.

Privatization was advantageous on the merits, but Enron had to be very careful not to spook ENE investors. The Belco nationalization by Peru, discussed in chapter 2, was not quite settled after seven years of effort. To align incentives and minimize expropriation risk, Enron put together a unique, diversified consortium: Perez Companc, a local industrial powerhouse; Citicorp Equity Investments, the largest bank in the country; and Argentine Private Development Trust Company Limited, composed of 21 international banks. Outside of the consortium, 30 percent of TGS was owned by the government and company employees. Finally, $53.6 million in risk insurance was secured from the Overseas Private Investment Corporation (OPIC), which put US taxpayers into the game.³¹

Enron had not parachuted in to win the bid. Enron had previously tried to launch a gas-liquids business in Argentina, and Enron Development was looking for power plants there. EOG’s joint-venture negotiations in the country had broken down, in fact, because of a lack of transmission capacity for new discoveries in the south. Little surprise that Enron heard about Argentina’s privatization plan early and was all-in when the official announcement came. And little surprise that Argentine officials visited 1400 Smith Street en masse to secure a bid. (A false but widely believed story says that Argentina was forced to accept Enron’s bid by George W. Bush, at a time when his father was the US president.)

The 1.3 Bcf/d, 3,800-mile system had averaged 85 percent utilization from four major gas-distribution customers under long-term firm contracts that fully subscribed the line. But TGS was in disrepair. Expertise and capital were badly needed, and the Enron-led consortium promised a minimum of $75 million on the front end.

“Enron expects to realize significant profits over time from this transportation-only pipeline via improved operating efficiencies.” Goals for 1993 were higher throughput from better marketing, new capacity from better use of existing compression, and a 30 percent workforce reduction—all preapproved by the government. Such restructuring allowed Enron contractually and profitably to lower transportation rates, which were pegged to the US dollar to manage currency risk. The five-year rate agreement, in effect, offered incentive rates for the project.

On December 29, 1992, just weeks after winning the concession, 40 Enron executives arrived to oversee the remaking of a large pipeline system. One hundred additional hires would be made from the operator side. The incumbents, each government-approved, were interviewed in competition for positions. Several hundred would be laid off with severance.

TGS was a mini-Enron, beginning with “a vision, core values, and key corporate objectives that covered every aspect of the business.” State-of-the-art gas-measurement controls were installed, as were new systems for accounting and finance, information technology, and human resources. Compensation and a new corporate culture strove to create a meritocracy where seniority and cronyism had previously ruled. It was, compared to Argentine standards, progressive.

The new, improved TGS increased its historic throughput under Enron management. But large industrial customers were being curtailed during the winter peak, when households and small businesses got priority. An open season was held to see whether users would underwrite an expansion to get firm instead of interruptible service. Expecting 90 MMcf/d, subscriptions came in for 210 MMcf/d.

At a cost of $86 million, TGS capacity would be increased 25 percent (240 MMcf/d) in mid-1994. An Enron-led construction bid was chosen by Energas, the Argentine authority. This increased Enron’s net investment within its $75–$115 million forecast and was the first part of the consortium’s $153 million, five-year requirement.

TGS “positions Enron for future growth opportunities in Argentina and South America,” Enron told investors in the 1992 Annual Report. Transmission and liquids marketing today, electricity generation and gas trading tomorrow; TGS was seen as a “springboard,” even a ‘“once-in-a-lifetime’ opportunity,” for Enron. Ken Lay now had a beachhead in South America, not only in Europe.

Enron could take some credit for what, during a period of time, was the third Latin American miracle. The best of Enron translated into the best for natural gas for southern Argentina. In addition to broader economic reforms that tamed inflation and generated prosperity, revenue from privatizations such as TGS produced “unheard of” budget surpluses in 1992 and in 1993. “By doing away with debt-ridden state-owned enterprises,” President Menem announced in August 1993, “we have eliminated very important pockets of corruption.”³²

Reorganizations, Multiplicity

Reorganizations were commonplace as autonomous Enron units built and managed projects outside North America. Reshuffling was also necessary to accommodate strong personalities, and none more than superdeveloper John Wing, who rotated between employee and consultant as circumstances changed.

In May 1991 came the first of the five major restructurings of 1991–93. A holding company, Enron Power Corp., was created to house (the renamed) Enron Power–U.S. and Enron Europe Ltd., with Wing as chairman of the holding company and its two units. Tom White was number two at the holding company as president and CEO, as well as president and CEO of Enron Power–U.S. Bob Kelly, still head of Enron Europe, was named vice chairman of the holding company.

Rising executive Rebecca Mark, vice chair of both subsidiaries, was named chief development officer to “coordinate all development activities.” This promotion put Mark in position to “plant the flag for Enron in as many developing nations as she could.”

Two months later, Wing resigned his positions to again become a highly paid Enron consultant. Wing could cash out his equity stake now that Teesside’s contracts and financing were done. His new arrangement also contained a big bonus to complete Teesside by deadline, his major responsibility. The Wing Group also was free to pursue its own power projects, while giving Enron a right of first refusal as investor.

With Wing nominally departed, Tom White replaced the man who had originally hired him and became the new chairman of Enron Power. Robert Kelly as head of Enron Europe reported to White. At the same time, Jack Urquhart, a member of Enron’s board of directors and a retired 41-year veteran of GE’s power side, joined Enron’s office of the chairman to advise Enron Power and “be responsible for coordinating our international strategies among our various business segments.” All this was to replace John Wing as much as possible—and provide stability. But strong personalities and fiefdoms within Enron’s far-flung international operations remained.

In early 1993, a major reorganization was implemented. Consolidating offices in Houston, Enron International (EI) was created with Robert Kelly in charge. EI’s main division was Enron Europe, which had jurisdiction for integrated gas-project development in the United Kingdom, the rest of Europe, the Middle East, and the former Soviet Union. EI was also given international liquids marketing (including Enron Americas) and the newly created Enron LNG.

“We believe this new organizational structure will allow Enron to manage its growing presence in the international natural gas marketplace,” Ken Lay and Rich Kinder wrote employees, “and enhance our position as the world’s first natural gas major.”

Kelly went over his big plans in a feature in Enron Business magazine. EI’s “first priority” was a 700 MW gas-fired combined-cycle plant, at Humberside, 150 miles south of Teesside. With construction permits secured and gas supply and transportation under contract, Enron and partner IVO, a Finnish company, awaited power-sales contracts to build. (This contract mismatch would not be rectified; the project was not built.)

Three power plants in Turkey were in negotiation with the Turkish government, the most likely for year-end completion being a 400 MW gas plant in Marmara. A joint agreement was near completion with Russia’s Gazprom to upgrade a major gas pipeline in the Volgograd region, the major conduit to supply southern Europe. (Bigger projects, such as one in the Russian republic of Kalmykia, would not materialize.)

A proposal to refurbish a 300 MW power plant in Kuwait was envisioned as the start of a Middle Eastern presence. An international strategy to market gas liquids and petrochemicals (including MTBE and methanol) was under way. A 30-year “non-binding joint venture agreement” with the Chinese city of Shenzhen by Enron Liquids International for liquid petroleum gases (LPG) was executed six months later.

Kelly saw economies of scope as Enron’s niche. “Synergy may not have a lot of meaning in other companies,” he intoned, “but at Enron International, it’s one of the secrets to our growth and continued success.” Project-financed LNG projects were also envisioned in the Middle East and in the Americas.

Three separate Enron divisions were active internationally as Kelly consolidated EI. One was Enron Development Corporation (called EDC or just ED), which was headed by Rebecca Mark. ED housed Enron Power, the unit that had jurisdiction over integrated gas projects in Latin Americas, India, and the Far East (including the Pacific Rim)—all the areas not within Enron International’s Enron Europe. Enron Power also held all the US cogeneration projects that John Wing and Rebecca Mark had previously developed, but new US projects were not being begun.

ED’s “market-led approach,” defined as “finding solutions to a country’s energy needs rather than selling a specific fuel or pushing a specific project,” resulted in several completions. Two Philippine projects—Batangas (105 MW) and half-owned Subic Bay (116 MW)—came online in April 1993 and February 1994, respectively. Enron leased and operated a 28 MW facility at Subic Bay as well.

Another start-up was the 110 MW Puerto Quetzal plant in Guatemala, half owned by Enron.³³ The two-barge facility, the first in Central America to be privately owned, as well as project financed, supplied one-fifth of the country’s electricity.

Oil was the fuel choice for those projects despite Enron’s public relations image, which began and ended with natural gas. (This discrepancy between talk and walk would also be the case later in the decade when coal quietly became part of Enron’s portfolio.) Most of the same projects were remote and risky, requiring taxpayer aid, and not all would live up to the profitability expected from them.

The other two international divisions were subsidiaries of major domestic operations. Enron Pipelines and Liquids Group was the parent of Transportadora de Gas del Sur (Argentina), the earnings of which were reported in Enron International. A subsidiary of Enron Oil & Gas, Enron Exploration Company, was responsible for upstream activities outside North America.

Negotiations and soft agreements, trumpeted with press releases and photo opportunities, were commonplace at Enron. Outside of Teesside, TGS, and small oil-fired power plants, however, legal contracts to build and operate were elusive.³⁴ With Enron negotiating with sovereign governments at every turn, political help was needed.

In February 1993, Enron hired as consultants James A. Baker III and Robert Mosbacher, two Bush Cabinet members who were back in Houston with the reelection defeat of George H. W. Bush. Lay lauded the two’s “wealth of international experience” to help Enron “in the development of natural gas projects around the world.”

Baker, who as secretary of state got to know many foreign leaders intimately, pushed projects in Kuwait, Turkey, Qatar, and Turkmenistan. Mosbacher, the former secretary of commerce (and, briefly, Enron board member), knew energy by trade. In addition to lucrative up-front fees, the two would receive an interest in any project they helped to secure. None, however, would result.

A third consultant, Thomas Kelly, who had joined Enron’s board after winning fame as a Gulf War commander, was hunting down international business too, both for Enron and for John Wing’s Wing-Merrill Group. To help in China, if not elsewhere, Henry Kissinger also joined Enron’s stable of highly paid consultants. Ken Lay left no stone unturned.³⁵

In June, a second major reorganization was announced. To “speak with one voice” internationally, Enron International Group (EIG) was formed with two divisions: International Development (Rebecca Mark) and Enron International (Ray Kaskel). Regional vice presidents would be assigned within each group.

With John Wing carrying his own torch and Robert Kelly taking a new job as chief strategy officer reporting to Ken Lay in Houston,³⁶ Rod Gray was named head of EIG. Gray’s tenure would be short-lived, as discussed in chapter 12, all part of the trial-and-error of a still-young international company.

Separate from EIG, Enron Operations Corporation (EOC) was formed to take over international building and operating activities previously assigned to Pipeline and Liquids Group. Tom White was in charge, fresh off his triumph at Teesside. Earnings from TGS and other internationally operated projects were recorded within EIG—not EOC, which operated on a fee basis. Enron Oil & Gas, meanwhile, being a publicly traded company 80 percent owned by Enron Corporation, continued to operate independently.

Dabhol (India) Project

A Rebecca Mark power project in India was envisioned as a Teesside-like opportunity for Enron Development. To Ken Lay, this was the beginning of a $20 billion Enron program to modernize the country’s electricity sector via a two-phased power project that represented the largest foreign investment in the history of the Republic of India.

India’s central planners were desperate. Their Eighth Plan (1992–97) forecast an 8 percent power shortage on average, 19 percent at the peak. Electricity was mispriced between user classes, and much of it simply disappeared. It was planned chaos, the term free-market economist Ludwig von Mises coined for economies run by politicians.

The options were few. The quality of India’s indigenous coal was going down and its price up. New domestic supplies of natural gas were limited. Government funds were scarce. India’s weak currency and volatile politics inspired little confidence.³⁷ Recent energy ventures there had burned the World Bank and other international parties. India’s downgraded credit ratings reflected the real chance of an international debt default.

Enron was all ears when Indian officials came prospecting in Houston in early 1992. Never mind that the traditional energy majors had little interest in a country hostile toward foreign capital. Contrarian Enron was hot to be the first—and exclusive—partner to rectify India’s power shortages. Lay bragged about going where the strategic planners said not to, and he had a flamboyant executive whose deals “positioned Enron not as the low-cost option but as the solver of the unsolvable problem.”³⁸

In late 1993, a $2.8 billion, 2,014 MW combined-cycle power project was inked with India’s Maharashtra State Electricity Board (MSEB). The all-in price of $0.073 kWh—denominated in US dollars given India’s double-digit inflation—was a jolt compared to the country’s current subsidized price that was estimated to be one-half of the long-run marginal cost of power.

The chosen site was near Dabhol, about 100 miles south of Bombay. The state of Maharashtra was the industrial region of the country, although it was desolate and impoverished.

The $930 million, 696 MW fuel-oil-fired first phase—“which we expect to have financed and under construction in 1994”—would be followed the next year with the LNG phase once contracts were in place.

Phase I’s 20-year, $26 billion power-sales agreement was the work of Rebecca Mark. Out of the shadow of John Wing, her decision making at Enron in different international capacities would make her one of the most consequential figures in Enron’s history—and a model for entrepreneurial shortcoming.³⁹

Enron got its tough terms in the purchased-power agreement (PPA). The project was technologically doable. But was it affordable—or even politically salable for a government du jour? Moody’s had just downgraded the country’s credit, and the World Bank rejected aid to a project it saw as too much, too soon. Phase II’s LNG was far more expensive than indigenous coal, not to mention oil. And who could ignore that about one-third of the region’s power was stolen or just not metered, which left MSEB chronically poor?

The lure of 30 percent returns—triple that earned in home markets—was a powerful one if Enron could lay off risk. Equipment supplier GE and contractor Bechtel each took 10 percent, leaving Enron with 80 percent. The plan was for Enron to sell down 30 percent of Phase I to become half-owner for an equity investment of $135 million, comparable to that of Teesside. But because India was a developing country, government financing was also sought (as it was not with Teesside), to better Enron’s chances for project financing.

Enron’s contract, the result of one-on-one negotiations rather than a bid process, built in not only high returns but also protections. Under a 90 percent take-or-pay clause, payments were denominated in the US dollar, not the Indian rupee, to limit currency risk. The buyer (MSEB) was liable for cost escalations associated with fuel costs or plant operations (including transmission service). Government guarantees were secured at the regional and central levels.

Mark got her terms across the board. But the Dabhol contract was J-Block in reverse; the sell was executed but with a poor, unstable sovereign. The paper-strong project was trouble waiting to happen, despite the flood of good press and goodwill that both parties bestowed upon each other.

Export-Import Financing

Enron Development’s goal was “to reduce Enron’s risk on the international market to those similar with normal commercial operating risk that one might have in this business in the United States.” But how was this doable outside of Canada and the United Kingdom, particularly in capitalist-unfriendly undeveloped (or developing in euphemistic terms) countries?

In fact, Enron was taking risks that others would not. But such daring was aided by taxpayers, the major agencies being the Overseas Private Investment Corporation (OPIC) and the Export-Import Bank (Ex-Im). “In most cases, in other countries we insist on OPIC insurance, expropriation insurance,” Ken Lay told Natural Gas Week in 1991. “We certainly look for higher rates of return in these projects than we would in the U.S., and even then we want to make sure to tie together the cost of the project, the marketing arrangement on the product and so forth.”

OPIC insurance help for Enron in 1992–93 included TGS-Argentina ($53.6 million in 1992; $62.6 million in 1993), Puerto Quetzal-Guatemala ($73.8 million in 1992), and Batangas ($50 million in 1993). A gas-liquids project in Venezuela (Accrogas LNG III) received an Ex-Im loan of $65 million, as well as public financing from France ($90 million) and Italy ($40 million). Enron Production Company, the foreign arm of EOG, also got into the act, receiving $100 million in OPIC insurance approval for its 1993 Trinidad play.

Then came the granddaddy. The Dabhol, India, plant was teed up with taxpayer assistance: a $302 million loan by Ex-Im and $300 million in insurance from OPIC.

That was just the beginning of taxpayer involvement with Enron’s overseas ventures. Before it was all over, “at least 21 agencies, representing the U.S. government, multilateral development banks, and other national governments,” approved $7.2 billion for 38 Enron-related projects in 29 countries. Many of the projects would not have gone forward without the guarantees or actual investment.⁴⁰

But the half-truth evolved that Ken Lay and Rebecca Mark’s Enron Development was “spreading the gospel of privatization and free markets to developing nations.” In fact, Enron was applying crony capitalism to inhospitable areas and press-spinning its global aspirations to swell its stock price. The result was more politicking at home and loosened business norms that would create problems for Enron later in the decade.

Breakout—and Peril

Enron’s breakout year for international was 1993. Teesside was in full operation. TGS was off to a very profitable start. Smaller power projects were getting done. Negotiations in a variety of countries, many remote, promised an earnings future.

Momentum was in the air with fancy press releases. But too many agreements to negotiate did not result in agreements to build. A toehold in Russia (pipeline repair) did not turn into projects. The Middle East did not provide even a toehold, much less a beachhead. Shenzhen did not turn into Enron’s “China Connection.”

This left large bets with the J-Block/CATS deal for expansion in the United Kingdom and the European Union, as well as with Dabhol in India. Neither would come to replicate Teesside. Worse, each would become an albatross around Enron’s neck. Ken Lay’s fast-forward ambitions to become an international energy major would leave him with a heavy price to pay.

Tight-Sands Gas: The Tax-Credit Boom

“A significant event occurred for EOG in late 1990 when federal legislation was passed providing tax credit incentives for developing natural gas production in tight sands areas,” reported Hoglund in EOG’s 1991 annual report. Such reservoirs, he explained, otherwise would require “production enhancements limiting their economic viability for drilling and development at today’s prices.”

The Omnibus Budget Reconciliation Act of 1990 provided a tax credit of $0.52/Mcf for natural gas sales from qualifying tight-sands gas wells drilled in 1991–92. The pretax benefit of $0.80/Mcf equated to a 50 percent increase in the then wellhead price.⁴⁴ “If one were to describe a tight sands company,” Hoglund told shareholders, “EOG would probably fit the description better than any other company in the industry.” Far from coincidental, Enron and EOG “diligently” worked to give an expired credit new life. “We spent a lot of time working that issue and actually got an extension of the Section 29 credits, which had, frankly, expired,” remembered Joe Hillings, head of Enron’s Washington office. “Enron essentially was the biggest winner in that legislation.”

With the changed economics, EOG “did a 180-degree shift” to develop, or acquire to develop, qualifying properties. The result? EOG tight-sands gas reserves were about double that of the US-company average of 25 percent. Parent Enron rejoiced. “The supportive role Enron Oil & Gas played in the passage of tight sands legislation … could be worth more than $100 million to Enron on a net present value basis.” Texas, too, aided tight-sands gas, and thus EOG, with a 10-year severance-tax exemption for sales from wells spudded between May 1989 and August 1996.⁴⁵

The newly tax-incentivized reservoirs were already in play. In 1989, two trillion cubic feet of unconventional gas was produced with the trend sharply upward. Tax incentives and federal grants between 1980 and 1990, $2.4 billion and $250 million, respectively, were having their effect. Still, with the Gulf War creating an anti-oil environment, natural gas reaped new political hay.

The huge tax-side revenue enhancer was yet another example of industry-driven—and Enron-driven—rent-seeking. As part of the National Energy Strategy project of the US Department of Energy under Bush-appointee James Watkins, important segments of the oil and gas industry concentrated their efforts on tax breaks to improve the after-tax economics of domestic drilling. The Independent Petroleum Association of American (IPAA) and the Natural Gas Supply Association were joined by gas associations of the midstream (Interstate Natural Gas Association of America) and downstream (American Gas Association). The battle cry was gas-for-oil in the name of energy security and national security. The energy majors got into the act, complaining about the relatively higher tax burdens at home than abroad.

Some free-market voices dissented. Noting the historically low price of natural gas, equating to $7 per barrel of oil (1991), and the failure of government energy subsidies, economist and industry consultant Arlon Tussing argued for government neutrality. “I simply don’t see why,” he testified before Congress, “it is necessary for government to subsidize [natural gas] … to penalize the production or consumption of conventional fuels.” Public policy should simply be “opening up the access to natural gas supplies throughout the economy” and “removing the barriers to the cheap and efficient delivery of this commodity throughout the country.”

The 1990 political coup for gas created some buyer’s remorse the next year when prices collapsed. Summer (off-peak) prices of a meager $0.50/Mcf, if not less, were reported in the Rocky Mountain region. Oil’s price woes in 1986 were now joined by natural gas in 1991. Both the IPAA and NGSA reversed course to oppose extending the benefit for wells drilled after 1992. But the math was complicated, given that one-third of all active rigs were in Section 29 formations. IPAA went back to favoring an extension just months after opposing it; other groups were too conflicted to take a position.

It could be state versus state. Oklahoma producers complained that New Mexico, rich in tight-sands gas, was taking away the California market. “It’s another energy subsidy, and it distorts the whole damn system,” complained one Sooner State producer.

EOG, however, stayed the course as the top beneficiary. “If properly focused,” Hoglund told a congressional subcommittee in early 1992, “the section 29 credit is the best vehicle to stimulate domestic natural-gas production and reserves.” His argument: “The producer is required to assume all the drilling risk, and the U.S. contributes to the investment only if the venture is successful and gas reserves are increased and the gas is produced.”

A scorecard of what a company produced in what proportions of conventional versus nonconventional gas drove the debate. “This is, after all, not a philosophical discussion,” as John Jennrich noted in another context, in Natural Gas Week. “This is about M-O-N-E-Y.”

Tax policy would steer EOG in the next years. Hoglund announced tight-sands gas drilling as “the most important emphasis for 1991.” A budgeted $100 million for 150–200 new wells was expected to create $10–$15 million in incremental income.

In 1991, wellhead gas prices fell almost 10 percent to $1.37/Mcf—more than 50 percent below the average EOG received in 1985. Still, a good year was recorded with tight-sands gas production leading. Not only did the company beat its forecast by earning $17 million from the credit alone, but also the benefit accrued to the parent. “Tight gas sand income tax credits resulted in a significant contribution to Enron’s after-tax net income,” Lay and Kinder reported.

EOG’s tax play peaked in a “tremendously successful” 1992, with “optimization of tight sands tax credits” resulting in 500 wells producing $42.5 million in tax-credit income. Seen another way, 95 percent of EOG’s natural gas reserve additions in 1992 was in “tight sand qualified areas,” which contributed to a record gas versus oil production tilt of 94 percent to 6 percent. (Oil never had a similar credit.)

EOG’s profitability would have been less in a more neutral tax environment. But production from its conventional properties would have been higher, onshore and off. And wellhead prices would have been higher, a factor that led companies lacking in tight-sands gas to oppose the credit, such as Anadarko’s Robert Allison, the very executive Lay tried to recruit before pursuing Hoglund.

EOG could not get an extension of qualifying wells past 1992, although it tried.⁴⁶ But spudded wells had a 10-year credit window. In 1993, EOG’s tax gain would fall by half and decline thereafter. Still, more than $100 million in legacy tax savings would accrue in the next decade as wells drilled in 1991–92 gave their bounty.

In first-quarter 1993, the total active US rig count sagged from the end of the tax credit for new wells. Still, EOG was optimistic as a “low cost producer” with “a large inventory of non-tight-sands gas prospects that have been developed and/or on hold.” There was another reason, although left unstated: Gas prices could be helped only by less drilling and less production in tight-sands gas.

A curious sidelight of EOG’s involvement with tight-sands gas was the role of prepayments from Chase Manhattan bank. Said a congressional staff report in 2003: “Enron would not have been able to utilize its Section 29 tax credits in 1992 and 1993 without the taxable income generated by prepayment transactions.” The same prepayment scheme was then continued by Enron to produce the cash flow that wasn’t coming in under mark-to-market accounting. Bankruptcy examiner Neal Batson argued in 2003 that the prepayments had amounted to “unsecured loans” from the bank, but British Justice Jeremy Cooke ruled that Enron had a plausible justification under US accounting principles for giving them non-debt status.

Technology “Mini-Renaissance”

Unlike Ken Lay across the street, Hoglund emphasized cost cutting and personally set the example.⁴⁷ “We run a lean, decentralized organization at EOG,” he emphasized, invoking his company’s industry-wide reputation as such. A company profile in early 1993 announced, “EOG is well on its way to becoming the Walmart or the Southwest Airlines in the exploration and production (E&P) industry.”

Between 1989 and 1992, EOG reported a one-fourth decline in operating and interest expense: $0.48/Mcf. New technology, readily adopted and sometimes pioneered by EOG, reduced the time and effort to find and produce energy.

“EOG also has benefitted from what I have described as a ‘mini renaissance’ within the oil and gas industry,” Hoglund explained in the 1991 annual report. “At the same time that gas prices are depressed and drilling rig counts are down, there have been some very significant technological advances which have provided tremendous opportunities for EOG.” Viewing underground formations in 2-D and 3-D seismic at “state of the art” geophysical workstations was one improvement; improved well-site equipment and more experienced crews were others. An employee-invented drill bit resulted in six- to seven-figure savings for EOG.

Most interesting was a technology that only decades later would become the talk of the industry. “New reservoir fracturing technology has significantly increased production capacities, making many drilling areas economical that wouldn’t have been within the realm of possibility three to five years ago, particularly in tight-sand areas,” Hoglund reported to investors in early 1992. This had started earlier; tripled delivery in 1990 from the Frio and Lobo areas of south Texas was attributed to “the company’s extensive seismic experience in the area and leading-edge use of modern hydraulic fracturing technology.”

Enron Synergies

Approximately half of EOG’s gas production was sold to either a pipeline or marketing affiliate of Enron. “The numerous synergies between EOG and other Enron Corp. companies are expected to provide additional benefits in the 1990s as the industry trends toward longer term supply arrangements,” Enron’s 1989 annual report stated.

Indeed, a long-term contract with Enron Power, priced at a hefty premium to the going spot price (regulatory related, as described in chapter 5), helped EOG in 1988 and 1989.⁴⁸ Gas Bank 1 prominently included EOG supply. A series of long-term contracts with Enron Gas Marketing (EGM) in the early 1990s added to EOG’s financial category: “other gas marketing revenues.” Marketing by Enron Oil Transportation & Trading was synergistic for both parties.

Combined with production hedges executed by EGM at EOG’s request, which in 1990 covered 30 percent of EOG sales, Enron synergies produced incremental revenues of $51 million in 1990 and $80 million in 1991. Hedging won revenue for EOG again in 1992 before 1993’s price rebound shrank the gains.

Enron’s need for EOG’s bountiful tax credits was another synergy. A Tax Allocation Agreement required Enron to pay EOG the value of utilized tax credits. Numerous service agreements between parent and affiliate were carefully done, given Hoglund’s fiduciary responsibility, and the benefits of sound economic calculation. “Enron Oil & Gas intends that the terms of any future transactions and agreements between Enron Oil & Gas and Enron Corp. will be at least as favorable to Enron Oil & Gas as could be obtained from third parties,” EOG told investors.

International (non-Canadian) exploration and production was facilitated by Enron’s growing global presence and reputation, particularly from Teesside. The strategy was to invest in areas with low up-front costs potentially yielding large reserves. Acquired tracts in offshore Malaysia, onshore Egypt, the North Sea, eastern Syria, and Indonesia (South Sumatra), however, accounting for 3 percent (1990), 6 percent (1991), and 4 percent (1992) of EOG’s capital budget, did not result in significant finds. Deal hunting in Australia, China, France, Kazakhstan, and Russia, some involving coal-bed methane, would come up dry.

EOG recorded its first major success outside of North America in 1993 with a major find off the southeast coast of Trinidad. The “fast track” project, commercialized in the first year of the concession, would grow into an important profit center in the years and decades to come.

Jawboning and Politics

While EOG reaped large tax profits, Enron complained about low wellhead prices and advocated state-level regulation to reduce supply to increase price (market-demand proration).⁴⁹ Therein lay a major public policy irony.

In 1991, Ken Lay roiled the industry with his accusation that the majors were exhibiting “economically irrational behavior” by selling their gas “below replacement cost.”⁵⁰ While stating that “EOG is not dependent upon rising commodity prices,” and roundly benefitting from the tax credit that effectively boosted its wellhead price by half, Forrest Hoglund jawboned for higher prices too.

EOG calculated that every $0.10 shift in wellhead prices was worth $8.5 million at the bottom line. Deeming low prices unacceptable, Hoglund aggressively shut in production with EOG’s short-lived wells, which provided between one-fourth and one-third of EOG’s total deliverability in the years 1990–92. “With prices at $1.20/Mcf, I think we can make a pretty good case for not selling what we have rather than drilling for new reserves,” he explained. This was for non-tight-sands gas; tax-credit gas was really $2.00—and more adding Texas’s severance-tax exemption.

At a state-of-the-industry gathering hosted by the Texas Railroad Commission (TRC) in 1991, Hoglund complained about “a truly chaotic market for producers, featuring month-to-month sales on the spot market.” EOG was shutting in gas that would otherwise (according to the company) sell below its replacement cost, and instead of following suit, other firms were “dumping” their gas in the market.⁵¹

“Buyers of natural gas are a whole lot smarter than the sellers,” Hoglund chided. “Unfortunately,” he added, the inexorable forces of supply and demand would have to make the correction. EOG’s chieftain advocated market-demand proration whereby the TRC and like state authorities would set allowables (force shut-ins) to restrict supply to increase prices to the proverbial replacement

costs. This, to proration advocates, reduced “waste,” defined by Hoglund as gas lost, owing to uncompleted reserves, scaled-down fracturing of new wells, older wells becoming uneconomic, and unconnected new wells.

Lay supported mandatory proration only as a last resort. While EOG banked on its voluntarily shut-ins to qualify as mandatory proration, leaving the competition with more of the pain, Lay’s broader Enron math included two offsets. State proration might reduce the gas needed to maximize pipeline throughput, and higher gas prices would narrow the margins of Enron Gas Liquids.⁵²

Meanwhile, other upstream industry parties were bemoaning that unconventional gas—not only from tight-sands gas but also coal-bed methane—was flooding the market and depressing conventional prices. Calculating deliverability of 22 Tcf/d chasing 18 Tcf/d of gas demand, at least at the desired price, and witnessing growing reserve additions, one conventional driller described the credit as “another special-interest, pork-barrel budget boondoggle benefiting only a handful of natural gas producers.”⁵³

Hoglund’s Touch

Hoglund’s approach was more than low cost; it was judiciously stocking the cupboard. The balance sheet was “extremely conservative” with low debt and high cash. Reserve replacement was steadily positive with the years 1989–93 recording 165 percent, 128 percent, 146 percent, 135 percent, and 139 percent, respectively. Well-timed hedges and long-term sales that beat spot prices—such as an innovative $326 million, 124 Bcf, 45-month volumetric production sale from EOG’s biggest field, the Big Piney in Wyoming—were part of this result.

By 1993, Hoglund was a star performer at a star company—and a hedge of sorts to the living-on-the-edge parent. Average wellhead prices and production in 1993 increased 21 percent and 25 percent, respectively. The wellhead average—$1.92/Mcf—was the highest since 1985’s $3.19/Mcf. Net income and cash flow soared to $138 million and $521 million, both records.

Tax-credit production of 295 MMcf/d, 42 percent of the total, generated special revenue of $65 million, 47 percent of the total. Investors were quite pleased too; EOG’s stock price at year-end 1993 was 50 percent above 1989’s close.

With his five-year employment contract maturing in September 1992, Enron extended Hoglund by three years to 1995. Hoglund’s hiring, and this extension, would be among the best decisions made by Lay and Enron’s board of directors in their all-too-brief 17 years. The Enron-enacted tight-sands-gas tax credit (“We decided to take advantage of this tax credit by going all out,” remembered Hoglund) certainly was behind EOG’s success. But sans tax farming, with wellhead prices that much higher, Hoglund and EOG would have still done well—as they would in the future.