Operating Results

Enron’s three divisions—natural gas transportation, exploration and production, and gas liquids—sagged in the new price environment.⁷ The Gas Pipeline Group (GPG) lost volume to residual fuel oil and had to discount transportation rates from the FERC-set maximum to be competitive. At the same time, take-or-pay liabilities increased for Enron’s three interstates, given fewer takes of system supply and lower prices paid at the wellhead. Year-end 1985 claims of $125 million, which had been expected to rise to $395 million in 1986, would end the year at $750 million. Still, after establishing a financial reserve for expected losses, well-managed GPG earned $191 million in 1986, only 9 percent below the previous year.

Enron Oil & Gas (EOG), advertised as the second-largest domestic independent oil and gas producer in the United States, reported a slight loss in 1986, although cash flow was strongly positive.⁸ A nearly 50 percent increase in gas production—the result of an active, successful drilling program—negated most of the 40 percent drop in gas prices. EOG pruned its workforce by one-fourth. Operations were consolidated, and headquarters was moved from Midland to Houston. All awaited a price rebound.

Enron Liquid Fuels reported a yearly loss with lower revenues from ethane, propane, butane, and natural gasoline sales, as well as lower margins for gathering and transporting crude oil and petroleum products. Mike Muckleroy was aggressively consolidating the operations of two companies, but there was just too much supply relative to demand for profitability.

Overall, Enron recorded a net operating loss in 1986 of $81 million. But asset sales (“earnings from discontinued operations”) produced a $139 million gain, which allowed Enron to report net profits of $78 million in a depression year for upstream-to-midstream oil companies. Transco lost $23 million in 1986, and its problems were just beginning. Still, Enron’s net income was a mere 15 percent of what HNG and InterNorth had reported separately just two years before.⁹ Under federal public-utility regulation, GPG’s rate base was entitled to several hundred million dollars alone.¹⁰

What rescued Enron’s year was the $600 million sale of Enron Chemical Company to National Distillers and Chemical Corporation, netting $121 million after taxes. Falling energy prices substantially helped the company previously known as Norchem, which had been earning about $25 million per year (before capital costs). Sharply lower fuel expense increased margins for polyolefin resins and other chemicals used primarily for making plastics. But going forward, a cash generator was lost, and Ken Lay no longer had this countercyclical division. Enron was now betting on higher energy prices to benefit all divisions excepting Liquids.

The income statement showed no effect from Enron’s other major asset sale in 1986: 50 percent of Florida Gas Transmission Company sold to Sonat Inc., for $360 million. Ken Lay had paid a pretty penny for the pipeline 15 months before, and the general market for energy assets had weakened. But on the strength of Florida Gas’s expansion plans, Enron was able to recoup half of its investment. The break-even deal removed debt from the balance sheet, reducing interest expense and making almost everyone a tad less nervous. (A contemplated half-sale of Transwestern was not consummated.)

The appreciated presale value of Enron Chemical in 1986 was a rare bright spot in a tough year. Another positive—or so it seemed—was Enron Oil Corporation (EOC), the oil-trading division of Enron International; EOC recorded earnings of $27 million in 1986. What could be better than a profitable subsidiary requiring virtually no capital investment? Enron’s 1986 Annual Report pictured EOC president Lou Borget and explained: “The volatile oil prices experienced during 1986 benefitted earnings of this group as profits are generated on margins and on the skill of the trader, not on the absolute price of the product.” Was this Enron’s answer to price volatility in either direction? Or was it too good to be true? Ken Lay and Enron would soon find out.

Innovative Pipelining

“During 1986,” Enron’s annual report trumpeted, “[our natural gas] pipelines led the industry in the creation of innovative ways to serve widely different markets.” Necessity inspiring innovation, Enron’s four major systems (Houston Pipe Line, Transwestern Pipeline, Florida Gas Transmission, Northern Natural Pipeline) and four joint-venture lines (Northern Border, Trailblazer Pipeline, Texoma Pipeline, Oasis Pipeline) collectively increased their market share in a year when natural gas usage fell 6 percent across the United States. Enron’s 37,000-mile network delivered 14 percent of the US total, up from 13 percent the year before. Still, this relatively good performance could not mask a bleak fact: Gas demand had not been this low since the 1960s when Robert Herring received HNG’s baton from Bus Wimberly.

HNG’s previously segregated interstate and intrastate units were consolidated in late 1986 (the second consolidation that year) to create the Gas Pipeline Group, headed by James E. (“Jim”) Rogers. Gerald Bennett, still over HPL and Bammel storage, now reported to Rogers, as did the three interstate pipeline heads and Ron Burns, now executive vice president, gas transportation.

In early 1987, the interstates integrated as Enron Gas Pipeline Operating Company. The “single networked system,” as described in Enron’s Annual Report, was an industry first. Centralized supply procurement was introduced with Enron Gas Supply Company, headed by Transco-ex Claude Mullendore. To deal with FERC, a Regulatory & Competitive Analysis group was formed.

“This consolidated management and business philosophy allows Enron’s separate natural gas businesses to use their combined strengths to greater advantage,” the annual report stressed. Still, as compared to hub-and-spoke organization, which itself might have been “more theory than fact,” integration and centralization were hype and hope. The pipelines were not built as a system, and federal open-access banned intracompany preference.

The challenge for each pipeline was to stay fully utilized between sales and transportation, maximizing revenue and minimizing take-or-pay liabilities. But with national gas demand down 20 percent from 1979, owing in large part to federal policies favoring coal in electrical generation, the natural gas transmission grid was overbuilt just about everywhere. The result was intense gas-on-gas and pipe-on-pipe competition, not to mention interfuel rivalry (oil-to-gas, purchased power-to-gas, and so forth).

It was showdown at the pipeline corral. FERC Order No. 436, effective November 1, 1985, ended the special marketing programs (SMPs) that many interstates had used to substitute (spot-gas) transportation for their (noncompetitive) system sales.¹¹ Electing open-access transportation under the restructuring rule was a tough call given that take-or-pay liabilities would mount when customers bought lower-priced spot gas and paid transportation fees. But few pipelines could continue in the old world of bundled deliveries if a rival elected to go open access because markets had surplus carriage capacity.

In April 1986, Transwestern became the first interstate to accept the provisions of FERC Order No. 436 and open access. Northern Natural Gas Pipeline soon followed. Florida Gas, situated as the lone pipeline serving peninsula Florida (although Coastal Corp. was making noises about building an interstate to there), would not open for several more years.

The fact that Transwestern and Florida Gas bracketed the industry’s transformation was all about the bottom line. Ken Lay was not a philosopher; nor was Enron an ivory tower. Lay and Enron were pragmatic profit seekers operating in a mixed economy. “Markets” and “competition” could be embraced here but not there—and sometimes in contradiction to company rhetoric and even stated company policy.¹²

Transwestern’s move to nondiscriminatory transportation was part of a negotiated settlement of its three-year (FERC) rate case, which conveniently coincided with the implementation of Order No. 436. The key sign-off came from Transwestern’s predominant customer, Southern California Gas Company (SoCalGas), the local distribution company for most of Southern California, with approval from FERC and the California Public Utilities Commission (CPUC). The wide-ranging agreement included an obligation by SoCalGas to buy a reduced quantity of system supply and otherwise choose from a menu of transportation rates offered on Transwestern. Abolished was the minimum-bill provision of the sales contract, which had been already been cut to 40 percent from 91 percent pursuant to FERC instructions and was also in legal jeopardy.

Transwestern had substituted transportation for sales to deliver at capacity to California in 1985. But gas demand fell in first-quarter 1986 when mild weather lowered heating demand, and electric power plants behind SoCalGas burned cheaper low-sulfur residual fuel oil. Transwestern’s throughput fell to 60 percent of capacity, the lowest in company history.

Reduced gas demand for space heating could not be helped. But if a complex of private-sector agreements could be combined with regulatory change, the loss of sales to oil was reversible. Jim Rogers, the head of Enron Interstate, sent Transwestern marketing vice president Clark Smith to California to begin the process.

Job One was negotiating a delivered spot-gas price with San Diego Gas & Electric (SDG&E) that would return its power plants to gas. Working backward, SoCalGas first agreed to discount its intrastate transportation rate, as Transwestern would do interstate. For both transporters, some revenue was better than none. Producers selling to Pacific Atlantic Marketing Inc. (PAMI, Transwestern’s gas-marketing affiliate) were also accepting a lower price at the wellhead as a shut-in alternative, so all the permissions were in place to back out oil with competitive gas. With regulatory approval from the CPUC—the incentive being cleaner air by burning gas rather than resid—the first direct sale by an out-of-state gas supplier to an end user in California’s history commenced. It had been a whirlwind two weeks for Smith and all parties.

This bypass—Transwestern–PAMI contracting directly with a customer of SoCalGas—inaugurated a new era of gas competition in the state. Transwestern–PAMI would open a California office to market transportation and released gas directly to end users, coupling its deliveries to the border with in-state carriage by SoCalGas in the latter’s new transportation program. Reporting to Clark Smith was a young talent hired away from rival El Paso Natural Gas, George Wasaff, who would have a long career at Enron in different capacities.

In the first year alone, Transwestern added 15 accounts, where before there had been only 1—SoCalGas. Two of the new accounts were electricity heavyweights: Southern California Edison Company and the Los Angeles Department of Water & Power. The marketing effort even reached Northern California, where Transwestern’s released gas, transported on the Northern California leg of El Paso Natural Gas, was sold to Pacific Gas and Electric Company.¹³

Ken Lay and the top Enron brass, particularly Jim Rogers, were all smiles at Clark Smith’s presentation, “How the West Was Won.” The interstate gas industry, regulated since 1938, had few entrepreneurial episodes as good as this one. Multiple Enron profit centers, not just Transwestern–PAMI, were involved in California’s huge spot-gas market. Other Enron affiliates selling gas to California and transporting on either Transwestern or rival El Paso were Enron Gas Marketing (the company’s national gas seller, run by John Esslinger) and Panhandle Gas Company (the released gas arm of Houston Pipe Line, whose supply was escaping from Texas’s gas surplus).

Transwestern synergies were not only paying off for other Enron units; the interstate’s own revenue was exceeding its FERC-authorized margin on invested capital (depreciated original cost). Transwestern was bringing home between $60 and $65 million annually beginning in 1987, versus an authorized return of approximately $42 million. This feat was achieved not only by keeping the pipeline at maximum throughput day after day but also by a rate design whereby pipeline space could be sold twice: once to firm customers paying a demand charge, and again to interruptible customers paying a volumetric rate to use the pipeline space not used by firm customers. (Capacity-release programs, under which firm customers could sell their unwanted firm rights, would come later.¹⁴) Unsung heroes in Transwestern’s rate department had designed three-year rate cases that offered incentives for such extra performance.

Florida Gas Transmission had its own oil problem in 1986. Facing lost sales in Florida Power & Light’s (FPL) dual-fuel-capable plants, Florida Gas renegotiated its delivered gas price to a percentage of the Btu-equivalent price of low-sulfur residual fuel oil. A locked-in discount was a sure way to keep oil out—so long as gas producers would accept their netback price (the price received at the wellhead after subtracting the costs to reach end users) rather than the shut-in price, which was zero but had a take-or-pay claim.

The renegotiation worked as planned. FGT throughput stayed at capacity, despite some pain. In one month, July 1986, the formula tying gas to 65 percent of the price of resid resulted in a wellhead netback of $0.93/MMBtu, less than half that received the summer before.

This was defense. Florida Gas needed to play offense to justify the premium price paid by HNG to Continental Resources for the system less than two years before. Pipeline expansions would do this, but that required firm, long-term shipper agreements in addition to the contracted gas already being delivered. The goal was to ensure that FPL use FGT to build new gas-fired plants.

FGT had both tailwinds and headwinds. More electricity was needed in the state. Natural gas firing was environmentally preferred. Rapidly improving combined-cycle gas plants added to this advantage over burning oil in existing facilities and committing to coal in new facilities. But FLP had to demonstrate to the Florida Public Service Commission that electricity generated from gas was competitive with or cheaper than other alternatives, including imported power.

Could Enron guarantee on a multiyear basis what Florida Gas was already doing on a short-term basis: delivering gas at a discount to resid?

FGT’s capacity to ship gas to the state had not increased in a quarter century. FPL had a life-of-field warranty contract from Amoco, for 200 MMcf/d of gas delivered on FGT, but the field was depleting and the contract faced expiration. The state’s largest electric was contractually committed to transportation charges for gas that might not be there.

With gas shortages in the 1970s, the electrics had idled some of their gas-fired plants. Meanwhile, FPL built intertie transmission capacity to import surplus electricity generated by Southern Company’s coal plants just north of the state.

This situation created opportunity for both buyer and seller of transportation capacity. Enron’s Bruce Stram and Mark Frevert determined that new gas-fired generation was more economical and reliable than power imports. Replacing coal-by-wire with gas-fired capacity would also provide Florida’s electrics with more capital investment (rate base) for profit making.

Putting Enron’s money on the table, Frevert in May 1985 executed a letter of intent to supply an average 343 MMcf/d over 15 years to FPL (more in the summer; less in the winter). The gas was priced at a discount to resid, guaranteeing savings for the buyer. A contractual price ceiling kept coal-by-wire at bay.

FPL signed the contract, committing to the first expansion project on FGT since 1970, for 100 MMcf/d. The Phase I expansion would enter service in July 1987, and a similarly sized (Phase II) expansion was planned for two years later.

Enron’s Jim Rogers called the supply deal “a big gamble,” since the producer contracts were not yet in place. FPL was not obligated to pay for transmission on volume that Enron could not deliver under the contract, but the electric wanted full deliveries to meet its generation goals.

With the contract’s gas-delivery date commencing in mid-1988, Frevert had dual tasks. First, he had to get final approval for the transportation contract from the directors of FGT’s new parent (Citrus Corp., as of June 30, 1986), which held the half-interests of Enron and Sonat. Second, he had to secure 1.9 Tcf of flexibly priced gas. Citrus had, in effect, sold short, imprudently taking a naked risk on the equivalent of about 10 percent of annual US gas consumption.

As part of the deal, Citrus cancelled the Transgulf project, which would have converted part of Florida Gas to petroleum transportation, instead applying to FERC for a (second) 100 MMcf/d, $28.5 million expansion. FPL had helped anchor the original Florida Gas project in the late 1950s; new contracts were anchoring the first expansions since the Jack Bowen era.¹⁵

The supply risk turned out to be all Enron’s. Sonat CEO Ron Kuehn adamantly opposed increasing his company’s exposure beyond that already being taken with his company’s new investment.

With the contract hanging in the balance, Ken Lay put his company’s corporate guarantee behind the deal to get Citrus’s board to unanimously concur. Enron’s warranty assumed the risk of what otherwise would have been split equally with Sonat. So if FGT did not receive transportation revenue on supply that was contractually committed but not delivered to FPL, Enron would be liable to Citrus.

This done, Frevert and FGT executive Stan Horton executed a resid/gas price differential hedge with the global commodities conglomerate Louis Dreyfus as they worked to line up long-term supply to meet the contract.¹⁶ The bet was that gas could be found to meet and beat resid prices. After all, oil prices could not get much lower than in 1986, and Florida Gas still had been able to attract gas from producers. For his part, Frevert intuited that “markets would create [their] own supply,” a reversal of Say’s law of markets, namely, that supply creates its own demand.

Frevert’s hunt began at Enron Gas Supply (EGS), the newly formed procurement arm serving all of Enron’s pipelines. But EGS demurred, stating: “We don’t have it, nor can we buy gas like that!” So Frevert formed a team and went outside the company, where they found two megasuppliers: wellhead gas from Amoco, the nation’s largest holder of gas reserves; and liquefied natural gas (LNG) from Panhandle Eastern Corporation. The agreement for 120 MMcf/d, signed in April 1987, allowed Panhandle to reopen its Lake Charles facility to import Algerian (Sonatrach) supply.¹⁷

Importantly, and fortunately for Enron’s sake, both Amoco and Sonatrach were comfortable with a netback price tied to the market price of resid. This gave Citrus about 90 percent of the gas needed for the 15-year contract. The rest would come from spot-market purchases, which seemed to be a manageable risk.

FGT’s complicated spot-gas contract, priced off going residual fuel oil prices, with a variety of provisions to try to keep the deal affordable for both parties, began favorably for Enron. FGT was making its full margin on existing capacity, and Phase I capacity (as of July 1987), and Phase II capacity (as of September 1989). Profits were being made on the gas-supply contracts for Enron Gas Services.

But things reversed beginning in late 1990 and early 1991. Large monthly losses (to Enron, not Citrus) were being incurred with no relief in sight. The resolution of this contract, estimated to be $450 million in net present value and requiring an up-front payment to FPL, is described in chapter 6.

Northern Natural Gas Pipeline, the granddaddy of Enron’s interstates, faced stiff competition from other Midwest pipelines, some of which were bringing in cheap Canadian gas (as well as resid) to many of Northern Natural’s industrial markets in 1986. Using a new regulatory mechanism whereby rates could be changed on a day’s notice (as opposed to laborious filings with FERC or as periodically scheduled), Northern Natural was able to reduce tariffs, stay competitive, and retain throughput. It had been Transwestern, in fact, that first asked FERC for a flexible purchased-gas adjustment clause (“flex PGA”).

Northern did well in the transition away from old methods of doing business, for several reasons. In addition to flex PGAs to change rates, Northern benefitted from on-system and off-system marketing. Northern’s producer contracts were also more market responsive (price flexible) than most such interstate pipeline contracts. Compared to the competition, including Natural Gas Pipeline of America, one of the last great projects of Samuel Insull,¹⁸ Northern Natural did well with take-or-pay costs.

Proactively unbundling sales from transportation created two profit centers instead of one for Enron. Fending off oil with innovative contracts kept Enron’s throughput high in states two thousand miles apart. Designing and performing under rate cases won extra profit. Capacity was expanded not only to stay ahead of the market but also to create an incremental market that would otherwise go to a rival energy. This was what Lay’s new breed could do in the changed world of FERC pipelining.

It took much more smarts than ever before to keep the pipelines as cash cows. By getting ahead of transition (take-or-pay) costs and offering innovative products, Enron was earning what other interstate pipelines, such as Transco, were not. Many interstate pipelines, in fact, were not making their authorized rate of return in the late 1980s, given overcapacity. At the same time, pipelines were replacing their old “20-year, firm, fixed, and forgotten” supply contracts with two-to-five-year agreements that had price flexibility and market-outs.

Reorganizing Cogeneration

Cogeneration was a new technology that used 20–35 percent less oil or natural gas than prior technology producing the same amount of steam and electricity. Cogen became a business for independents when a provision in a federal law required utilities to buy the cogenerated power at a price determined to be the “avoided cost,” so long as certain conditions were met.¹⁹ John Wing and Bob Kelly got HNG into this business just months after Lay arrived from Transco Energy Company.

After negotiating the merger between HNG and InterNorth, Wing was set to develop a thriving cogeneration business pursuant to his employment contract. But InterNorth, the top dog in the merger, had its own cogeneration activity in Northern Natural Resources Company, ably run by Howard Hawks.

Northern Resources was off to a fast start with two excellent projects. Thus Hawks’s Omaha-based division assumed responsibilities for power development for the combined company. Wing left HNG/InterNorth under a five-year consulting agreement that gave him room to develop cogen projects independently, while giving Enron a right to invest.

Into 1986, Hawks’s mission, unchanged from the InterNorth days, was “to create new grass-roots businesses which are attractive in their own right and complement the Corporation’s various operations.” That was the case with the Central Basin Pipeline, a $70 million, 143-mile CO₂ pipeline project running from New Mexico to West Texas, that began operations in late 1985 and produced high up-front earnings. At about the same time, aligned contracts allowed construction to begin on a $152 million, 440 MW cogeneration facility adjacent to Union Carbide’s petrochemical complex in Texas City.

Both projects were equity financed by InterNorth but not off the balance sheet, which would involve other parties putting up the capital and taking the risk. Not that such financing was a bad business practice; cash-rich InterNorth did not need it, and Hawks’s company liked simplicity and transparency. What you saw is what you got with this Midwest-culture company.

The Texas City project, originally named Northern Cogeneration One, had come together nicely. The contract specified that the sales price of steam and of power flexed up or down with natural-gas input prices, creating an arbitrage spread. (Fixed-priced multiyear gas was not yet available.) The 140 MMcf/d needed to produce the steam and power utilized existing InterNorth agreements for offshore gas and for transportation on Houston Pipe Line. Dan Dienstbier’s Northern Natural Gas Company made the arrangements, but it took some prodding from Hawks—he threatened to go outside the company for gas—to finally get things done.

Union Carbide agreed to buy all the steam and 30 percent of the power from the proposed plant. That left 70 percent of the plant’s cogenerated electricity for sale. Houston Lighting & Power Company (HL&P), a franchised utility, was building coal and nuclear capacity and did not need the power—at least not at a high-enough “avoided cost” price to make the project viable. But there was a potential solution. Dallas-based Texas Utilities Electric Company needed power and could pay an attractive avoided cost—if the power could be delivered to North Texas.

The bottleneck was broken by some (more) political capitalism when the Texas Public Utility Commission intervened to force HL&P to deliver (“wheel”) the power up to Texas Utilities. (Actually, a power exchange between the two utilities would eliminate the need for physical transportation altogether.) The 12-year contract was for 393 MW, the largest power contract ever executed between a cogenerator and a utility. The deal, completed just when InterNorth announced its acquisition of HNG, was a triumph for Northern Resources. Construction began later that year, and, on paper at least, the arbitrage returns between locked-in input and output prices were substantial.

But circumstances had reversed. After energy prices collapsed in March 1986, Northern Resources found itself stuck in neutral—and worse. Given its imprudent debt, Enron needed cash coming in, not going out to construction payments. The word from Houston was to wind down outstanding negotiations and sell Central Basin Pipeline. That left Texas City, just several months in construction, facing the prospect of being financed by Enron’s treasury (but indirectly debt-financed for the most part, given Enron’s indebtedness).

Enter Michael Milken and Drexel Burnham Lambert, whose high-yield junk bonds were used with 50 percent ownership going to Drexel. For $10 million, Enron owned half and operated the 450 MW plant. The facility would become operational in early 1987. But Enron had sacrificed much in the process of getting money in the door by year end—and demoting Hawks in the process, explained in the next chapter.

Another cogen project that Enron wanted to do—even with its own scarce capital—did not originate from Northern Resources. It was a project that Howard Hawks told Mick Seidl he would not authorize without renegotiating its terms, creating a rift between Houston and Omaha. The project concerned a proposed $120 million, 165 MW plant in Bayonne, New Jersey, sponsored by Cogen Technologies Inc. (CTI), a company founded by Robert C. “Bob” McNair.

McNair was new to the business. He had precious little equity, coming off a setback in which one of his trucking companies declared bankruptcy amid the industry-wide retrenchment that followed deregulation.²⁰ But McNair was smart, diligent, likable, and an able negotiator. He would eventually repay his creditors, exit trucking, and enter a field that would turn out to be phenomenally successful. He would also eventually sell his company to Enron and go on to bigger things.²¹

McNair originally presented a 22 MW cogeneration project to Mick Seidl, who sent him to John Wing. The two met, but McNair’s 50/50 profit-sharing proposal was a nonstarter given that HNG would be putting up the equity. Talks were suspended when Wing was pulled away to consummate the merger between HNG and InterNorth.

Postmerger, Wing was out and Hawks in. But McNair was not going to fly to Omaha to negotiate with Hawks. Wing was the key to getting a deal done, something he agreed to do for a 1 percent personal-interest carry, given that things were falling into place with a gas provider, steam buyer, power purchaser, and project constructor (GE). Better yet, the project was growing well beyond its original size, and McNair was proving adept at resolving the politics of siting and permit issues.

It was a strange situation—Wing as McNair’s consultant, negotiating with Enron, where he also consulted. Enron’s board had to approve this arrangement given the conflict of interest. But far from fooling anyone, Wing’s contract required that he give Enron the right of first refusal to invest in any of his new projects. This became moot given Enron’s capital constraints, but it showed to what extent Wing had Lay’s ear.

While negotiating on behalf of HNG, Wing had wanted 85 percent of the free-cash flow to go to the company, not 50 percent as McNair proposed. That was still a good starting point. Now, wearing three hats—his own, McNair’s, and Enron’s—Wing saw a compromise to flip from 85/15 to 50/50 should the project’s return on investment (ROI) reach 23 percent.

This was doable and good for all sides. But given how well the project was coming together, McNair, in return for the 85 percent concession on the front end, wanted a second flip in his favor should the project reach a still higher profit threshold. Maybe it was because few really thought that a 30 percent ROI was possible. Maybe it was McNair’s likability and effective one-on-one negotiations with Lay and Seidl at a Young Presidents’ Organization retreat. Maybe it was Wing’s strong support of the deal and Lay and Seidl’s respect—or fear—of Wing. But whatever the reasons, McNair got the Houston brass to agree. If Bayonne’s ROI reached 30 percent, Cogen Technologies would receive 85 percent of the free cash, leaving Enron with 15 percent for the life of the project.

It was this three-tiered proposal that Howard Hawks wanted to renegotiate—not approve as Mick Seidl, Enron’s president, wanted him to do. Thus the Bayonne project was in stalemate in the spring of 1986.

Given the order from Houston for Northern Resources to retrench, as well as the impasse with Bayonne, Hawks began eyeing life after Enron. Ken Lay too knew that major changes were necessary, so he turned to Wing for help. Could Wing refinance Texas City to free up Enron’s $152 million in committed project costs, even if it meant selling part of the project? Lay also wanted to pursue cogeneration projects off–balance sheet, something that Wing, a superdeveloper-promoter-closer, could do.

Wing agreed and renegotiated his consulting contract with Enron for a third time, upping his monthly stipend and establishing a special payout, assuming that Texas City could be profitably refinanced. As part of the deal, Enron Cogeneration Company (ECC) would be created, with Robert Kelly running the division from Houston, where he was already reporting to Hawks. At the same time (June 1, 1986), Northern Resources became Enron Development Company (EDC), with Hawks as president, charged with selling the CO₂ pipeline and, if capital became available again, investing in new projects.

But Hawks had had enough. With permission from Lay, Hawks set out to buy Central Basin Pipeline from Enron as part of his exit strategy. A few calls to the right energy companies resulted in an $87 million offer, but Lay decided to sell Central Basin externally.

Hawks negotiated a severance payment and began networking around Omaha, where resided a number of severed InterNorth employees who were capable and interested in work. In a matter of months, Hawks found a stalled cogeneration project that he and a few others got back on track. April 1, 1987, was the first payday for a company that christened itself Tenaska, a sort of reborn Northern Natural Resources Company.

Today, Tenaska is one of the top-20 privately held companies in the United States, with assets of $3.3 billion, annual revenue of $8 billion, and an enterprise value of $1.5 billion. With 10 percent of the nation’s natural gas either sold or managed and more than 24,500 MW of electricity under management, Howard Hawks’s company is what Ken Lay’s (contra-capitalist) enterprise ultimately failed to be.²²

With Wing on the outside and Hawks gone, Robert Kelly was now in charge. He hired former Omaha talent, such as Jay Berriman, and new talent, including Rebecca Mark, who had been in the treasury department of Continental Resources Company when it was acquired by HNG in late 1984. Kelly also had straight access to now-Enron consultant John Wing.

Kelly’s ECC began to revise the Texas City contracts to allow refinancing, which Wing did pronto. The 165 MW Bayonne deal was executed with Enron agreeing to invest $14 million for a 42 percent interest. Other partners that Wing brought in with Bayonne were GE (the builder), Jersey Central Power & Light (the power buyer), and Transco (the gas supplier). The extraordinary profitability of the project that launched Bob McNair’s Cogen Technologies is discussed in chapter 5.

Buying Independence

Takeover specialist Irwin Jacobs took a blow from the merger of InterNorth and HNG. InterNorth stock, which had been selling in the low $50s per share from takeover rumors, fell to $47 after HNG was acquired. But rather than sell out, Jacobs increased his stake. By third-quarter 1986, Jacobs and associates owned 5.1 million shares of common. In July, New York–based Leucadia National Corporation disclosed an ENE accumulation of 2.3 million shares.²³ Together, the arbitrageurs (arbs) had accumulated 16.4 percent of Enron’s common stock, which was mired in the low-to-mid $40s.

What to do? Lay’s first plan was to take Enron private, with senior executives taking ownership positions. Lay, Rich Kinder, Jim Rogers, and Gerald Bennett flew to New York to work with leveraged-buyout specialist Kohlberg Kravis Roberts & Co. Lazard Frères was busy assisting Enron on the deal as well.

The trick was finding a price that stockholders would accept—say, $55 per share—while not assuming so much debt as to endanger ongoing profitability. But to get to a marketable buyout price, projected earnings had to be sweetened from what the Enron divisions originally projected. Thus they were pressed to up their volume and margin forecasts—not unlike what HNG had done to get its $70 per share price from InterNorth. But energy markets were much worse now than then, and Lay was joined by more prudent colleagues.

The concerns came out during the last night, dinner consumed and drinks flowing. “I have been pushed way beyond my level of comfort,” Bennett confessed to Lay in reference to his intrastate gas assets. Rogers, speaking for the interstates, chimed in: “I am probably the best regulatory man in the country, but I am not this good.” Lay responded: “Well, if you guys don’t think we can make it work, then we’ll drop it, get back to Houston, put our heads down, and try to make it work.”

Enron then asked Lazard Frères and Drexel Burnham Lambert to explore other options for remaining independent. Lay visited some deep pockets in search of equity. But nothing clicked, so negotiations ensued with Jacobs and Leucadia to purchase their shares.

On Monday, October 20, 1986, Enron announced a buyback of the 7.4 million shares for $47 per share, a 6 percent premium to the prior day’s close. A special charge to earnings of $20 million would be taken for this difference.

But the real hit was a $180 million devaluation of Enron from a $4 per share fall in ENE upon the announcement. One million shares were dumped, mostly by disappointed speculators. The takeover premium was now completely out of the stock. Wall Street arbs, taken by surprise, exacted their revenge.

Lay and the board had hoped to avoid this by simultaneously authorizing a potential stock buyback of up to 10 million shares, depending on market conditions and business considerations. Enron also estimated a $45 million increase in annual cash flow from the tax benefits of the transaction. The market was little impressed.

Clear-the-decks, get-this-behind-us would be Ken Lay’s pain-avoidance strategy—now and all the way up to the final months of Enron’s solvency. Each time, Lay was nothing but positive. “This agreement removes a major, disruptive uncertainty about Enron’s future created by short-term oriented speculators,” he wrote in an all-employee memo. “Our directors, our employees and our shareholders are now in command of the company’s destiny.” The decision, Lay added, “brings to a close the long period of restructuring, realignment and reorganization that began with the merger of InterNorth and Houston Natural Gas.” Still, he admitted, “this freedom has a cost.”

The deal disadvantaged general stockholders and worsened the company’s debt ratio at a vulnerable time. And unfortunately for Ken Lay, who treasured good public relations, a fellow industry leader, T. Boone Pickens, was crusading for shareholder rights at the time.

“Greenmail is a symptom of weak management, and Enron’s executives folded in a big way,” complained the chairman of the newly formed United Shareholders Association (USA). Digging hard, Pickens called the event “Black Monday” and characterized the buyout as “an ‘ongoing job security program’ for Enron executives.”

Ken Lay had been a big Boone Pickens fan. After all, this was the man who had shaken the cage of the stodgy oil majors with his attempt to buy Gulf Oil Company, something Ken enjoyed watching. But Boone had gone too far—way too far—by ridiculing Enron in a press release for the national media.

Lay fired off a three-page rebuttal to his critic. The missive mentioned how Pickens’s Mesa Limited Partnership had recently paid Irwin Jacobs a “slight” premium in its takeover of Pioneer Corporation. Lay argued that Enron’s value decline would be eventually regained from the benefits of the buyout, including a better-motivated workforce. It was “careless” for Pickens to denounce Enron’s senior management as “weak” and “entrenched.” Lay added:

I have been chief executive officer of Enron Corp. less than one year, which hardly seems long enough to be too entrenched. More importantly … many people in our industry … believe Enron Corp. has one of the strongest and deepest senior management teams of any company in the natural gas industry…. Many of the innovations within the industry in attempting to adapt to the rapidly changing market and regulatory environment have been initiated by this team.

“My respect for Boone has certainly diminished substantially because of this matter,” Lay scribbled in a note to his old boss and friend Jack Bowen at Transco, attaching a copy of his letter.²⁴ But otherwise the communication remained private. As much as Pickens violated his ego, Lay thought it best not to feud in public over the matter. This was a hard time, and a war of words with an industry icon would scarcely help. Only a more profitable Enron would vindicate the stock buyout and enhance his (Lay’s) image.

Enron’s special friends in the investment banking community spoke up. “It is a black mark on the investment business that arbitrageurs are able to wreak havoc on a well-run operation due to their concern only with short-term gain,” commented Joseph Culp of First Manhattan Company. Still, he and virtually everyone else had to agree: This was another clear-the-decks action for Enron’s balance sheet. Even after profitable asset sales of over $1 billion, Enron’s debt ratio would end 1986 at 69 percent, a slight improvement from the year before but a far cry from Lay’s goal, announced just 11 months earlier, to end the year at 55 percent.

Even if the buyout failed to impress externally, the major selling point internally was the creation of a new employee stock option plan (ESOP) from the stock purchase, financed by a tax-free $230 million transfer from an overfunded retirement plan that had been earmarked to retire company debt, as well as $105 million of new bank debt.²⁵

Coupled with the stock already distributed to employees from prior programs, one-third of Enron’s outstanding common stock would be employee owned. To Ken Lay, this put the incentives in the right place.²⁶ But short-term stock performance might become overemphasized within the company, particularly one run by hurried, über-confident Ken Lay.

The ESOP would prove to be an employee bonanza in the coming years. And it created a thirst for continual stock appreciation by virtually every Enroner—and pressure to get it. Removing “investors who we believe sought short-term profits at the expense of higher long-term returns” would itself over time create a hyper-short-term bias.

High-risk debt securities (junk bonds) issued by Drexel Burnham Lambert financed part of the deal with Jacobs, which continued the relationship between Lay and Drexel star Michael Milken. (Between 1985 and 1988, Drexel financed eight Enron transactions, totaling nearly $3 billion.) Milken would always be a favorite to Enron’s chairman, even after the financier’s (controversial) criminal conviction on finance and tax charges and Drexel’s bankruptcy in 1990.

Public Policy Overtures

Government intervention in energy markets had long been driven by competitively harried executives, not only by outside reformers invoking the common good or consumer groups seeking a free lunch. The political capitalists, aka rent-seekers, could come from small or large companies. The common denominator was effective organization and follow-through to obtain the requisite services of the right politicians or bureaucrats at the right time.²⁷

Not surprisingly, the collapse of energy prices in 1986 inspired acts of political capitalism. Transco Energy CEO Jack Bowen used his annual report to call for an oil tariff sufficient to guarantee a domestic floor price of $25 per barrel (about double the current price). Oscar Wyatt championed oil protectionism at Coastal Corporation. Richard O’Shields, CEO of Panhandle Eastern Corporation, called for the federal government to prorate (limit) gas supply to gas demand and to stabilize (increase) prices. “The odd thing about free enterprisers is that they can’t stand free enterprise,” observed John Jennrich, a University of North Carolina political science major and now editor of Natural Gas Week. “They want certainty.”

Enron’s fortunes were tied to oil and gas prices. Announcing a 38 percent cut in planned capital spending in 1987 from the prior year, CFO Keith Kern calculated a $15 million hit to Enron’s annual cash flow for every drop of $1 per barrel of oil or $0.10 per Mcf of gas at the wellhead. Thus Enron was keenly interested in promoting public policies to increase energy prices—natural gas (and gas-liquid) prices for their own sake and oil prices to help natural gas and liquid prices. (Enron had no coal investments at the time.)

Dr. Lay and Dr. Seidl—PhD economist and PhD political economist, respectively—ominously noted the “sharp swing toward dependency on foreign oil” in Enron’s 1986 Annual Report. But they stopped short of advocating an oil tariff. They were not averse to such a policy but viewed it as politically undoable. They also believed that they had cleared the decks one last time, meaning “all costs associated with the merger and the sharp drop in energy prices are now behind us” and foresaw a price rebound from “fundamental economic and political forces.” But such optimism and patience would be tested in the future, and Ken Lay would be partial to quick-fix political solutions in lieu of (slower) market adjustment, as discussed in chapter 7.

On another front, Ken Lay donned a free-market cape to help his industry and Enron. Part of natural gas’s problem was a federal law passed after the severe gas curtailments of the winter of 1976/77, which restricted the use of oil and gas in existing and new industrial facilities and power plants. “The choices now for electric utilities are basically coal and nuclear power,” the Carter administration’s National Energy Plan concluded at the time. The idea was to ensure that the supposedly dwindling resource of natural gas would not go to “low priority” boilers at the expense of “high priority” residential and commercial markets. Natural gas was “too good to burn,” a refrain went.

Despite a gas surplus that began almost on the day that Carter signed the Powerplant and Industrial Fuel Use Act of 1978 (Fuel Use Act), the law remained on the books. Exemptions were being granted, particularly for new gas-fired cogeneration projects that its sister federal law PURPA encouraged.

Still, the Fuel Use Act sent a chilling signal that long-term commitments to natural gas were a political risk. By 1986, the American Gas Association (AGA) made repeal a legislative priority, and in March of the next year, Ken Lay testified before the House of Representatives in Washington to that end. Enron’s pipeline expansions required long-term commitments from these big gas users, and every bit of incremental gas demand was needed to help raise prices.²⁸

“Everyone agrees the ‘gas bubble’ will soon disappear,” Senator Howard Metzenbaum of coal-rich Ohio said in his opening statement, to which Lay replied that the “18-month/2-year gas bubble has been about to burst for eight or nine years.” It was a sad story for the upstream industry. Gas deliverability was increasing, while gas demand had fallen almost 15 percent in five years. What the gas industry needed—and deserved with new technology turning gas into electricity more efficiently and cheaply than ever before—was a level playing field, a policy of “let the market be the test.”

Lay issued a challenge at the hearing. “We say to our friends in the coal industry: ‘You build a coal unit: We will build a combined cycle,’ and then we’ll go head-to-head to see who will sell electricity to our friends in the electric business.”

Ken Lay was on a crusade. But as much as he enjoyed external matters, particularly those in his old haunt of Washington, DC, his attention would soon have to be back inside Enron’s walls in Houston. His creation was not yet on track two years after the merger, and a big festering problem was just ahead.

A Star for Enron Oil & Gas

After integrating InterNorth’s properties, Enron Oil & Gas Company ranked as the second-largest US independent oil and gas producer in terms of reserves. Concentrated in South Texas and New Mexico, with some Canadian operations and a number of Gulf of Mexico blocks, daily production in 1986 averaged 350 million cubic feet of gas and 10,720 barrels of crude oil and liquids. Gas production increased nearly by half from the year before, and low selling prices were partially offset by lower drilling costs.

EOG’s fortunes rose and fell with prices. The price depression in 1986 resulted in a one-fifth staff reduction, closed regional offices, and consolidation in Houston “to position the company for the future.”

EOG’s lineage went back to 1951, when HNG formed Houston Natural Gas Production Company. Two decades later, Robert Herring bought Roden Oil Company as part of a West Texas gas play, renaming the division HNG Oil Company. When W. F. Roden retired in 1982, Ted Collins Jr. became head of HNG Oil, which was still operating in Midland. By 1986, Collins presided over a much bigger enterprise, post-InterNorth.

There was room for improvement. Seidl had his strategic planner, Bruce Stram, compare HNG Oil’s return on capital to its cost of capital. The answer was sobering. McKinsey consultant Glen Sweetnam reconfirmed that what HNG Oil thought to be strength—profitably finding oil and gas relative to other operators—was instead a weakness.

EOG’s 1986 cash flow of $205 million was respectable, given a 50 percent fall in received natural gas prices and one-third drop in oil and condensate prices from a year before. But the subsidiary was bulky. Properties needed to be sold and others developed. The tumult left the unit disorganized at its new home in Houston. Collins, tiring of corporate meetings at his new headquarters, was ready to cash out. A makeover of EOG under a new entrepreneurial eye made sense.

Ken Lay wanted the best in the business and had something valuable to offer: an equity stake in EOG, a unit that Prudential-Bache Securities valued at $1.7 billion if taken public. EOG had strong upside under the right management, a McKinsey & Company study for Enron concluded.

Lay first approached the head of Anadarko Petroleum Corporation, Robert Allison, who was interested and took the offer to his board, which informed him that a new compensation package was in the works. The sweetened deal kept him home.

Next on Lay’s list was the architect behind the stellar growth of Texas Oil & Gas (TXO). Forrest Hoglund was courtable. His company had recently been purchased for $3 billion by United States Steel Corporation (USX), adding a layer of management above him. Hoglund had signed a long-term agreement with his new bosses and was rumored to be in the running for the top USX job, but his contract had an out clause. What Ken Lay offered was the chance to participate in the appreciation of a valuable set of assets that were akin to what he had mastered at TXO.

Hoglund was presented with a five-year contract agreement that was competitive in base salary but superior in incentives. The kicker was a grant of 1 percent of the valuation of EOG when it was taken public.²⁹ EOG was worth at least a billion dollars, so that was $10 million and counting. This was not something that the Pittsburg-based company wanted to match, so Hoglund accepted Enron’s offer.

Forrest Hoglund was a veteran of the upstream industry. After graduating from the University of Kansas in 1956 with a degree in mechanical engineering, he began his career as an engineering trainee at Humble Oil & Refining Company. At Exxon, Hoglund rose to vice president, worldwide natural gas, before he was hired away by TXO as its new president in 1977. Hoglund became COO of Texas Oil & Gas two years later and CEO in 1982. His company roared with one of the highest and most profitable growth rates in the industry. One of TXO’s prime assets was Delhi Gas Pipeline Corporation, the owner of the South Texas gas lines that Jack Bowen had built in the 1950s.

Effective September 1, 1987, Hoglund became chairman and CEO of Enron Oil & Gas Company, advertised as the third-largest US independent, with a reserve equivalent of 1.7 Tcf. Similar to TXO, 85 percent of EOG’s reserves was natural gas and 94 percent domestic. Another similarity: the reserve positions were geographically concentrated and capable of benefitting from affiliated transportation and marketing services. Enron’s synergies and Hoglund’s entrepreneurship would make for a happy story starting in 1988.

Enron Gas Marketing

PURPA-driven independent power generation was not the only regulatory opportunity for Enron in the mid-1980s. The law of the land for interstate pipelines (under FERC Order No. 436, later taking final form as FERC Order No. 636) was mandatory open access that opened a profit door for buying and selling gas in interstate commerce. Natural Gas Clearinghouse (NGC) was the first out of the gate on a national scale, but, as Jeff Skilling would later explain, “they had the wrong concept.” NGC was a gas broker, not marketer, and its incentive and ability to secure interstate pipeline space for delivery was limited.³⁰ Northern Gas Marketing (NGM) had the right plan. But to be national, it needed transportation access on pipelines other than its affiliate Northern Natural.

The merger between HNG and InterNorth was just months old when open-access transmission became FERC policy.³¹ InterNorth’s NGM became the guts of HNG/InterNorth Gas Marketing, soon to be Enron Gas Marketing (EGM). The opportunity was there, but many customers for long-term contracts were haunted by the gas problems of the 1970s. Curtailments and moratoria had sent electric generators to coal, and even to nuclear, for their new capacity. Fuel oil also gained from federal price controls on wellhead natural gas.³²

The coal rush did not mean problem-free solid fuel. There were periodic labor union problems in the mines, and pollutants from coal plants were greater than from natural gas facilities for generated power. Still, coal was a known, abundant commodity. As prolific producers and as net exporters (in contrast to oil or gas), US coal companies offered power companies a secure input that was one-third to one-half cheaper than gas in terms of heating value. But coal plants were more expensive to build than gas plants, so much so that low gas prices flipped the economics.

But memories were long. Curtailments in interstate markets in the 1970s led to a federal law intended to phase out gas from industrial boilers and power generation. Price spikes, too, were an issue for gas versus coal. And even if gas supply was secure and cheaper, utilities were biased toward new coal capacity, given public-utility regulation. Capital-intensive coal plants created more rate base to be multiplied by the allowed rate of return. To utilities, coal was profit maximizing whether or not its generated power was more economic than from a gas-fired plant for their captive customers.

The statistics told the story. Between 1973 and 1988, the use of natural gas for electric generation fell 28 percent nationally, while the consumption of coal in its three flavors—anthracite, bituminous, and lignite—almost doubled. In Texas, gas usage fell 26 percent, while coal for power generation, starting practically from zero, increased tenfold. Robert Herring’s coal-for-gas vision in the early 1980s for Houston Natural Gas seemed prescient.³³

But North America’s gas resource base was not running down, judged economically, as Herring and many others in and out of the industry had assumed. Record prices in the 1970s and expanding technology in the 1980s did what few thought possible: create a surplus of supply relative to demand. The overhang of gas supply sent wellhead prices south—from approximately $2.25/MMBtu in 1985 to $1.75/MMBtu in 1986 and about $1.50/MMBtu thereafter. Given the lower capital costs of gas plants when compared to coal plants, this price reduction made the overall production costs of gas-fired electricity less than its major rival over the life of a prospective plant.³⁴

Low gas prices led to warnings of expensive gas to come—a so-called hard landing between supply and demand. McKinsey & Company’s John Sawhill, a former energy regulator, pumped this scenario. So did Groppe, Long & Littell’s Henry Groppe, a Transco Energy Company board director whom Ken Lay knew, liked, and retained as a consultant at Enron. The National Coal Association’s Richard Lawson self-interestedly spread this message as well, as told in chapter 7.

Thus Enron and Ken Lay faced a major challenge—and an opportunity. Utility commitments to build new gas plants required supply and price certainty to lock in the present advantage of gas relative to coal. (Nuclear power was stymied after the Three Mile Island accident in 1979.) Ken Lay understood this very well, as did McKinsey energy specialist (and Sawhill protégé) Jeff Skilling. Their response would define Enron’s first boom, as discussed in later chapters.

In early 1987, Enron’s largest subsidiary, Gas Pipeline Group, reorganized. The biggest change was separating the nonregulated merchant function from the pipelines. Enron Gas Services was created, housing Enron Gas Marketing (EGM) on one side and Enron Gas Supply (EGS) on the other. Reporting to Enron Gas Services head Gerald Bennett were EGM’s John Esslinger and EGS’s Claude Mullendore, both formerly with Lay at Transco. Bennett, who continued to head Enron’s intrastate properties at Houston Pipe Line and Oasis, reported to Dan Dienstbier, as did Jim Rogers from the interstate pipeline side.

Bennett’s job was to rebuild nonregulated markets, which meant securing gas supply to make long-term sales commitments. Enron Gas Supply was now charged with procuring supply for EGM, which prominently included released gas off Enron pipelines. Take-or-pay resolutions were part of this effort.

EGS/EGM was focused on markets outside the areas served by Enron pipelines, leaving the majority of on-system sales coming from the pipelines, from either their FERC-blessed jurisdictional supply or their released-gas spot affiliate. But some EGS/EGM gas was sold in Enron’s pipeline markets along with spot-gas packages from non-Enron marketers. All was at arm’s length; Enron’s transportation and gas marketing were “classy” compared to other interstates where the pipeline and its marketing affiliate could preferentially team up at the expense of independent marketers.³⁵

The highlight of EGM’s 1987—its “breakout moment” as remembered by head marketer John Esslinger—was a 10-year agreement to sell up to 60 MMcf/d to Brooklyn Union Gas Company, the fifth-largest gas-distribution company in America. Transco had provided this gas to Brooklyn Union ever since its line entered service in the early 1950s; now Ken Lay’s old company would provide transportation for EGM pursuant to FERC Order No. 436. The transaction, accounting for approximately 25 percent of the requirements for the New York City–based company, or enough gas for as many as 125,000 homes, began in November 1987.

Brooklyn Union president Elwin Larson stated: “[We are] convinced that Enron’s extensive supply and pipeline network will make a substantial contribution to our supply portfolio and will provide customers with a reliable and competitive source of natural gas well into the future.” Dienstbier spoke of “the opportunities available in a free-market environment for both buyers and sellers to benefit from market-responsible pricing mechanisms.” But mandatory open access, which enabled such third-party marketing, was part deregulation (of the commodity) and part reregulation (of interstate pipelines). It was a new FERC interpretation of just-and-reasonable pricing under the Natural Gas Act of 1938.

The terms of the agreement were not disclosed, but secrets were hard to keep in the industry. The long-term, guaranteed gas was fixed at a “hefty premium” to the then spot price, higher than any other contract but a portfolio hedge for Brooklyn Union should prices trend up. However, the contract contained “price bumpers” to trigger renegotiation should severe price swings occur.

The contract generated immediate high profits for EGM. But Enron did not have fixed-price, long-term gas to lock in a margin on the out months of the 230 Bcf deal. EOG production and reserves, not to mention Bammel storage, could come into play in a pinch. But Enron’s corporate credit backed EGM to perform—even to buy gas at a loss to honor the contract.

Brooklyn Union was a landmark deal. No commodity contract of this size had ever been made to a gas-distribution company in the history of the (regulated) interstate market. It represented “the first long-term nonjurisdictional contract that had been done on a 10-year basis,” remembered Esslinger, and it was just the beginning. Making bets that the buyers’ market in gas would continue, EGM consummated similar deals with Elizabethtown (NJ) Gas Company (10 years) and Northern States Power Company (5 years).

Multimonth, noninterruptible (firm) contracts commanded a price premium to spot.³⁶ Buyers were willing to pay more for first-in-line gas, if it was backed (at least implicitly) by a corporate guarantee. Those were the deals that Enron wanted as a producer and a marketer. Generally, the longer the term, the better the margin, at least compared to the current spot price.

Profits were not separated out by Enron, reflecting the embryonic and sensitive nature of margin making in this early period. What customer would want to read about how much profit Enron was making on the deal? Volume information was provided for the first time, and it was strong: 700 MMcf/d.

Ken Lay was pleased. He didn’t mind taking chances—big ones—in order to lead the market. Florida Gas and Citrus, after all, had done it on a grand scale in signing its 1.9 Tcf, 15-year deal with Florida Power & Light. The press noticed too as headlines told the business world how innovative Enron was. A story within the story was that Ken Lay’s new company was beating his old one with ex-Transco executives Claude Mullendore on the procurement side and John Esslinger on the sales side leading the way.