Cost Reduction: Staying Competitive

“The four companies have launched an offensive to identify better, faster, simpler—and more profitable ways to do business,” Enron’s employee magazine reported in Spring 1994. Necessity beaconed. Costs had to fall in an environment where actual revenues were below theoretical cost-based maximums from some combination of discounted rates, low throughput, or no-longer-collectable demand charges. This was no longer the easy game of padding expenses and maximizing the rate base and letting the gas sell itself. “Just maintaining the status quo wasn’t an option,” remembered Tom White, one of Enron’s top two executives overseeing the project.

One focus was substituting labor with fixed investment. Automation and modernization increased the rate base upon which pure profit was made, replacing dollar-for-dollar labor costs that earned nothing. And reduced expenses improved transportation economics in the open-access world.

One target was vintage compressor stations—the oldest of which dated from the 1930s on Northern Natural—that were manually operated by crews of four or five. New automation technology allowed Gas Control from Houston (Floor 42 of the Enron Building) to operate the stations remotely. The same was done with a redundant system in Omaha, the home of Northern Natural, should Houston’s operation ever become incapacitated.

At the same time, management layers in the field were reduced under each vice president of operations as self-directed work teams were trained and skill-based pay implemented. A thorough inventory of work skills per person resulted in combined duties and pay increases for some and terminations or buyouts for others. “We found out all sorts of interesting things,” White remembered from the skill assessments. One was literacy; some in senior positions could not read and depended on staff.

The results were dramatic. Enron’s interstates pruned just over one-fifth of their workforce in the first half of 1993 alone. By the end of the process, approximately 40 percent of the interstates’ overhead was gone. Reliability went up, as the gas moved per employee rose fivefold.

Field employment of Enron’s interstate pipelines fell from 130 to 19. One of Northern’s vintage compressors was relocated to a museum in Omaha. “I joked with Stan [Horton] that in 20 years there would be one man and one dog left at Clifton [Kansas],” Tom White recalled. “The man would be there to feed the dog, and the dog would be there to see that the man doesn’t touch any of the controls in the compressor station.”

Another cost initiative in 1995, the Performance Improvement Process, had cross-functional teams (about 40 across Enron’s pipelines) set cost-reduction goals. The “cultural change” removed the last remnants of the old cost-passthrough mentality. “Before, if people figured they needed something, they just bought it,” said one field leader. “Now they have to decide if they really need it, and then they have to check the money to see if they can afford it.”

Hundreds of thousands of dollars in savings were achieved in the first months alone from these different practices. Expenses per facility were consolidated by region and put out for bid. “Nit-picking’ expenses” were tracked for the first time. Legacy costs were eliminated (“Some locations were being charged for [phone] lines that were no longer in service—including a few dating back to the 1940s.”) Operations were conducted “a little closer to the edge” without compromising safety.

The cost-savings efforts were led by Horton, cochairman and CEO of Enron Operations, along with White, head of engineering and construction. (In 1996, EOC split into two parts to leave Horton as chairman and CEO of the Enron Gas Pipeline Group.) An expert at rate-case nuances and with operational smarts, Horton favored expansions based on sound economics, not what Enron criticized as a “strict rate-base mentality.” Enron’s markets were quite rivalrous, although FERC’s quantitative measurement of “workably competitive” (a controversial theoretical standard) said otherwise.

Transwestern Entrepreneurship

Transwestern Pipeline faced two major challenges in the 1990s. One was a pronounced capacity surplus to California from the entry of Kern River Gas Transmission, as well as expansions to the state by all three existing out-of-state suppliers, including Transwestern. The result was 7 Bcf/d of capacity chasing 5 Bcf/d of gas demand—a 30 percent surplus, one exacerbated by a regulatory distortion.⁹ Rate discounting—and empty space on El Paso and Transwestern, in particular—was predestined.

The second challenge was a provision of FERC Order No. 636 (1992), which sanctioned the permanent release of unneeded capacity by local distribution companies (LCDs) to their interstate supplier. With the capacity surplus all but eliminating the value of such first-call rights, Southern California Gas Company (SoCalGas) notified Transwestern that it would turn back its capacity effective November 1996 pursuant to the expiration of its age-old contract.

As Transwestern’s largest customer with firm capacity of 457 MMcf/d, or 60 percent of the pipeline’s historic capacity to the state, SoCalGas would be freed of its $51 million annual payment to Enron. It would pay only for volumes actually transported, not a cent in reservation fees, whereas before, Transwestern (and El Paso) had had an open-ended agreement that SoCalGas would pay demand (fixed) charges on 60 percent of its historical contracts.

Transwestern Pipeline had to execute a business strategy that few interstates ever had to employ in the entire history of the Natural Gas Act of 1938.¹⁰ The result was a “landmark settlement” that gave Transwestern partial relief, while implementing incentives to potentially secure more revenue. In return for SoCalGas’s continuing to pay a reduced demand charge for 5 years, Transwestern agreed to a maximum indexed rate for 10 years (the first ever approved by FERC) and removed gathering-line assets from the rate base with customer credit. Transwestern also got the right to resubscribe the relinquished capacity rights (by SoCalGas) for its own account.

The highly negotiated, virtually uncontested global settlement, another first for FERC, left Transwestern free of (three-year) rate cases until 2006, a 10-year window in which cost cutting and other efficiencies could bring incremental revenue to its bottom line. The agreement was regulation by contract, not regulation by FERC—what a pair of Enron thinkers several years before called a “‘social compact’ where long-term contracts among the affected parties set price and service terms” to displace regulatory expense and motivate greater entrepreneurial alertness for efficiency.¹¹

Compared with the default capacity turnback, Transwestern gained a guaranteed revenue stream until the state’s surplus could be worked down to give firm transportation rights economic value again. With low-cost Canadian gas coming into California, gas flows had to move east, which inspired three Transwestern initiatives: a 340 MMcf/d lateral expansion into the prolific San Juan basin of New Mexico for new supply, making its two Texas laterals bidirectional, and offering a joint Transwestern–Northern Natural transmission rate.

By 1996, the new Transwestern had 1.5 Bcf/d of capacity to the Golden State and, compared to little before, 1 Bcf/d of business east of California. Contrast this to when Enron bought the line in 1985: 750 MMcf/d west and 250 MMcf/d east. Ken Lay was correct when he told stockholders 11 years before that Transwestern “has the potential to increase its sales and transportation significantly during the next decade.”

Better yet, profitability was preserved and better opportunity created amid an unprecedented buyers’ market. The little sister in Enron’s interstate stable had tripled in size and was arguably the nation’s most entrepreneurial pipeline.

Florida Gas: Forestalling Entry

Incremental expansions on Florida Gas Transmission (FGT) in 1987 and 1991, each for 100 MMcf/d, just kept up with the market. Phase III, filed with FERC in late 1991, and facing potential entry from a new pipeline project cosponsored by United Pipeline and Coastal Gas Transmission (it would finally enter service in 2002), was much bigger.¹²

With existing capacity of 925 MMcf/d, FGT proposed to add 800 miles of new mainline and two new compressor stations, as well as upgrade existing compressors, for an additional 875 MMcf/d. The $940 million proposal was estimated to enter service in late 1994.

In early 1995, with the expansion scaled back to 530 MMcf/d (Phase IV six years later would make up the difference), FGT became a 1.45 Bcf/d, 5,275-mile system at a cost of approximately $1 billion. The sole gas provider to the Sunshine State was trying to stay that way with timely expansions, while building in cost advantages for future capacity growth. Cost escalation from environmental matters required prudency too.

The expansion was anchored by a firm transportation contract with Florida Power and Light, which was eager to both convert existing power plants from oil to gas and build new gas-fired capacity. Twenty-nine customers accounted for 99 percent of the new expansion, increasing Florida Gas Transmission’s sure-money revenue (demand charges, paid whether or not the customer shipped gas) to 90 percent from 19 percent back in 1990. Straight-fixed-variable rate design, shifting transmission fees to the must-pay side, instead of volumetric payments as gas was actually shipped, accrued to the benefit of Citrus Corp., half-owned by Enron and half-owned by Sonat, and run by Enron’s Bill Allison.¹³

Although the Phase III expansion was cut by 40 percent, costs did not fall proportionately. Unprecedented environmental requirements, in particular, added expense and time to the project. Some 2,300 gopher-tortoise “citizens” living near the mainline required “one of the largest relocations of a protected species ever attempted by environmental specialists.” And for the first time, FERC required planting trees and shrubs instead of natural revegetation along the right-of-way.

“It’s the right thing to do,” remarked one Enron official. But it was also legally required—and good business for regulated rate setting. The extra cost went into the rate base for a rate of return, and would-be pipelines that might enter FGT’s territory would be held to the same standard, increasing the cost of entry.

Northern Natural: Incremental Growth

With more than one-half the overall mileage of Enron’s interstates, Northern Natural Pipeline was the dominant supplier to the Midwest market, as it had been since its construction in the early 1930s. Northern’s expansive, dispersed market was mature compared to that of high-growth Florida and California.¹⁴ Still, as Enron stated in its 1994 Annual Report, Northern Natural’s “stable rate base, volumes, and margins have positioned it to produce consistently strong earnings and cash flow.”

Small expansions maintained the all-important rate base in the face of depreciating original cost. Two 100 MMcf/d increases were completed in 1996: one in Iowa, Illinois, and Wisconsin; the other, in Minnesota. Capacity of 4.1 Bcf/d was almost as much as Enron’s other three interstates combined.

Rate-case settlements before FERC were essential for Northern Natural’s profitability, as for every other interstate. A resolution was reached in March 1996 when a rate increase was withdrawn in return for customer agreements extending (expiring) firm capacity by two years, giving Northern much-needed firm revenue. Another rate case was obligated sooner than the usual three years to deal with an unresolved proposal for Northern to price capacity seasonally (rather than annually, which was the FERC norm) in order to better match demand and supply should LDCs unbundle and allow end users to buy their own gas. (LDCs would continue to hold transmission capacity.) As elsewhere, Enron was pushing the regulatory envelope at the state level as well as at the federal level.

In 1996, Northern Natural announced a $105 million plan to increase firm capacity by 350 MMcf/d, concentrated in the upper Midwest, between 1997 and 2001. While small by Enron standards, Peak Day 2000 was Northern’s largest expansion in 30 years. Every little bit counted; adding customers and capacity increased the rate base and allowed Enron’s largest cash cow to keep giving whole milk.

Northern Border: More from Canada

Operator Enron held a 9 percent ownership in Northern Border Pipeline, a 1.7 Bcf/d, 970-mile line bringing Canadian gas to the US Midwest. Of this amount, 70 percent was delivered to Northern Natural Pipeline at Ventura, Iowa, for redelivery to various Midwest markets.

“The largest deliverer of natural gas from Canada to the U.S.,” with a market share of 20 percent, applied to FERC in early 1995 to increase capacity by 15 percent for $700 million, mostly to bring more Canadian gas to the Midwest. This proposal was enlarged 40 percent to 700 MMcf/d with a new plan to reach Chicago, putting Northern Border in competition with existing suppliers Natural Gas Pipeline of America and ANR Pipeline, as well as a potential supplier (Alliance Pipeline) that had an entry proposal before FERC. The $837 million expansion, the largest such project under way in the United States, would come on stream in 1998.

Since its 1981 beginning, Northern Border employed a cost-of-service tariff, while Enron’s other interstates set rates under a fixed-variable rate design that allocated (mostly fixed) cost to the firm rate (demand charge) and other (mostly variable) cost to the interruptible rate. Northern Border’s methodology required firm shippers to pay all their transportation charges as a fixed cost, leaving the incremental cost of actually moved volumes at nil. (This rate design, which was common among transnationals moving Canadian gas to the United States, and which virtually eliminated risk for the builder, would be replaced with SFV in 2000.)

Firm customers fully utilized Northern’s capacity day in and day out. (“Since 1988, Northern Border has been transporting volumes at or near its maximum capacity.”) Under FERC Order No. 636, however, the contractual shipper could relinquish its firm space to a third party for credit (payment).

Enron’s interest in Northern Border was through its 13 percent ownership of Northern Border Partners LP (Partners), the other owners being Williams Companies, Panhandle Eastern, and TransCanada PipeLine. Partners, which owned 70 percent of Northern Border Pipeline, went public in 1993 as a Master Limited Partnership (MLP). Enron realized $217 million to help reach its corporate-wide earnings goal of 15 percent and “to repay debt and to fund projects that give us a higher rate of return and faster growth.” Enron remained operator and general partner for fee income, while maintaining the “synergistic benefits” of Northern Border for Enron’s other interstates and Canadian marketing office.

The MLP ownership structure, enacted by Congress in 1987 for natural resource and mineral companies, avoided the corporate income tax by issuing dividends straight to the owners. This meant that a full dollar was received compared to a full-tax-paid return of 60 cents. The three US owners of Partners were part of the MLP.

Enron Transportation & Storage

Enron’s heady vision back in 1987 of a “single networked system” was more hype and hope than fact, although the five-pipeline intrastate-and-interstate system experimented with centralized functions and produced some two-pipeline synergies.¹⁵ Florida Gas Transmission and Transwestern, in particular, combined their accounting, finance, and rates functions for a time.

Grid advantage was largely neutered by system-specific federal rate-and-service regulation, not to mention the MOA rules for pipelines. Gas Control on Floor 42 of the Enron Building showed a lighted screen of the five connected systems that Enron operated, but they were not functionally integrated. Still, there was much thought on how to “‘Enronize’ the pipelines.”

A few cross-country transactions utilizing displacement-and-exchange to eliminate physical transportation made the news, such as a Transwestern to Northern Natural to Florida Gas deal in 1994. Such deals were more for show than dough, but significant intersystem synergies emerged with Transwestern’s east-side expansion, which overlapped with the southern end of Northern Natural Gas Pipeline.

Effective March 1, 1994, Deb Macdonald and Bill Cordes, the respective heads of Transwestern and Northern Natural (both wholly owned by Enron) announced an integration to increase revenues and reduce costs. “Transwestern and Northern Natural Gas are combining revenue targets, business strategies, transportation services, and new product lines,” they stated. Other units of the two were also exploring joint optimization for their geographical overlap. The combination was tagged Enron Transport and Storage (ETS).

This experiment was taken to the next level in September 1996 when the eastern end of Transwestern and the south end of Northern Natural were merged into a new entity, Enron Transportation & Storage (ET&S). Both pipelines remained separate legal entities, with ET&S being an “umbrella organization” to “give new identity” to that part of Transwestern and of Northern.

A single marketing force now served the overlapping markets. Scheduling and billing were merged for “seamless service.” The goal of employees was to maximize profit for the new entity, not for one pipeline or the other, which was more money for Enron from fewer transaction costs.

Several factors made the de facto combination possible. Both pipelines had resolved their take-or-pay problems, were full open-access transporters, and had spun down their gathering systems (see pp. 445–46). Both had recently settled rate cases to provide some years of lightly regulated operation during which savings could flow to the bottom line. But most of all, the integration reflected the overlap of systems in West Texas and the Panhandle area of Texas and Oklahoma.

Stan Horton, the cochairman of ET&S along with Northern president Bill Cordes, saw the new entity as part of a “normal evolution of our industry.” Indeed, the Gas Industry Standards Board (GISB), empowered by FERC, was well along in codifying best standards to facilitate virtual integration in common company areas.¹⁶ But Horton’s observation touched upon another fact: gas-transmission synergies were undoing the regulatory balkanization of the industry.

Deregulation Not

Enron was a fount of action for lightening FERC’s regulatory hand. Under Jim Rogers, there were proposals for zone-of-reasonableness rates (1985); a gas supply reservation charge (1986), which later became the Gas Inventory Charge (1987–88); off-system interruptible sales service (1987); and flexible-purchase gas adjustments, or flex PGAs (1986, 1988). Monthly pricing within a cost-based framework was proposed by Rogers protégé Rick Richard at Northern Natural (1989). After securing FERC and CPUC approvals, Transwestern (1986) was the first interstate pipeline in California to bypass the local gas-distribution company and sell gas directly to a customer, thereby displacing residual fuel oil with gas at an electric power plant.

Transwestern and Northern Natural were the first interstates to declare for open-access transportation (1986). Transwestern became the first transportation-only pipeline three years later. Transwestern and Northern also filed deregulation proposals for released firm capacity, under which such capacity was turned back by the original holder and was (re)contracted to the high bidder in an open market.

Transwestern successfully pushed for expedited transportation for new interstate capacity in the wake of the Iraq war of 1990, the rationale being to displace (unreliable) foreign oil. Ken Lay lobbied FERC to adopt fair-value ratemaking for interstate gas transmission under which cost-based rates included (higher) replacement costs, not original depreciated costs, which was the way the agency treated interstate oil pipelines.

Rate cases were typically the vehicle for Enron pipelines to push against traditional regulatory boundaries. In addition to the preceding examples, proposals in 1991 for incentive ratemaking from both Florida Gas and Northern Natural were part of such three-year applications.¹⁷

But simply deregulating natural gas pipelines was not of interest to policy makers, however. The Bush administration’s National Energy Strategy (NES), released by the Department of Energy in 1991, advocated rate decontrol only where “pipelines do not possess market power.” The NES’s “magic of the marketplace,” in George H. W. Bush’s words, did not apply in midstream interstate gas markets unless a special quantitative finding was made by regulators.

This was the entrenched industry position affirmed by producers, marketers, local distribution companies. It was regulatory inertia, and not many regulators are inclined to deregulate. All this made the interstates shy about pushing generic decontrol on the rest of the industry despite the successful precedent of light-handed state-level regulation for intrastates (as in Texas).

Enron, looking for the practical, endorsed “a combination of cost-based rates, incentive rates, and/or market rates based upon the particular service and particular market.” Some free-market economists and libertarians associated with the Cato Institute and the Institute for Energy Research (IER) thought otherwise. In their eyes, full deregulation—with or without a phase-in—was workable.

While previously advocating relaxed regulation within a cost-based just-and-reasonable framework, Ken Lay endorsed full decontrol at a Cato-IER conference in 1993, becoming “the first chair of a major pipeline company to openly consider deregulating interstate transmission.” At the same time, and even in the same speech, however, Lay advocated government intervention in energy markets, also for Enron’s competitive gain.¹⁸

Lay’s self-interested position had a storied theoretical basis. FERC’s quantitative test of “workable competition” in light of an interstate’s “market power” was a methodology that assessed market-share ratios as calculated by the Herfindahl-Hirschman Index. HHI viewed competition and efficiency in static terms. It was an equilibrium analysis.¹⁹ Yet competition, as economists from Joseph Schumpeter to F. A. Hayek had stressed, is a dynamic, unfolding process, not a snapshot (or at-the-moment measurement) of current industry structure. The gains from entrepreneurship cannot be captured in FERC’s structure-conduct-performance model, because innovation is not a predictable, measurable action.²⁰ Yet dynamic efficiency was as or more important than static efficiency.

Opponents chided a market-process, qualitative view of competition. “A determination of sufficient competition cannot be made on an industry-wide basis, based upon anecdote, supposition, or Aristotelian Logic,” said a brief for the producer trade groups Natural Gas Supply Association (NGSA) and Independent Petroleum Association of American (IPAA). The nonintegrated gas industry, created by regulation, in turn created this (pro-)regulatory conflict.

“Slow-moving traditional regulation cannot respond to the quick changes that have resulted [from] … the expansion of competitive forces within gas markets,” stated one Enron consultant. “Rates generally misprice services: in peak periods services are not allocated to the highest valued uses, in off-peak periods the pipelines are not used as fully as they could be, and administratively set rates fail to provide proper signals for entry and exit decisions.”

Imperfect competition, as defined, moreover, cannot be policed and solved by immaculate regulation; there is government failure in the quest to address market failure. Opined Lay in his Cato-IER keynote address, “Imperfect markets are often better than perfect regulation,” implying that even the best government action is often worse than government inaction.

In 1996, an internal Enron task force envisioned what a new set of free-market FERC commissioners might propose to reinterpret the Natural Gas Act’s just-and-reasonable standard regarding market substitutes for regulation. The Deregulation Notice of Proposed Rulemaking (D-NOPR) hypothesized a free-market FERC replacing cost-based regulation and entry-and-exit authority with “market reliance and self-regulation through Commission-sanctioned settlement contracts.”²¹ The inspiration for this new thinking came from Transwestern’s global settlement, under which the parties, with FERC’s blessing, entered into a contract that essentially replaced federal regulation with a long-term contract. Regulation was, in a sense, privatized—with lower costs and legal certainty.

Given FERC’s guiding philosophy of guilty until proven innocent, Enron’s interstates continued to push for lightened, market-conforming regulation in the mid-1990s. Some fell short from upstream and downstream opposition. These opposing parties saw stringent cost-based rates as a wealth transfer from the regulated party to themselves—a zero-sum view as opposed to the dynamic view that greater product choices and new entry would be encouraged by free-market incentives.

As it was, FERC talked big about market reform but was never comfortable about voluntary negotiations and let-the-market-decide. Not even incentive regulation, a stated priority of FERC from the late 1980s through the mid-1990s, got off the ground.

Transwestern’s global rate settlement in 1995 left the pipeline virtually deregulated until its next obligatory rate case ten years later. In the same year, Florida Gas proposed to index its cost-of-service rates to inflation for a five-year period and otherwise offer customers the option of negotiating rates and service different from the regulated default (the recourse option). What ended up being chosen under this “market matching program” depended on “the creativity of shippers trying to match their unique market circumstances in order to maximize flexibility, efficiency and value.” Like a similar proposal by Florida Gas back in 1991, this proposal fell short of FERC enactment.

In 1996, Northern Natural pitched its Skyline proposal, under which shippers paid market-sensitive seasonal rates so that (other things equal) rates would be higher in the peak winter season and lower off-peak. Such scarcity pricing would be within an overall cost-based revenue ceiling under which higher-than-regulated rates would be balanced by lower-than-regulated rates within the same year.

Gathering Deregulation

While mainline interstate-pipeline markets were not considered “workably competitive” by federal regulators, gas pricing at the wellhead and at market hubs were. Producer price controls had created natural gas shortages in the 1970s, a black mark on administrative regulation under the Natural Gas Act of 1938. Federal legislation in 1978 and in 1989 removed all price ceilings with little effect because of the gas surplus.²²

This left gathering lines, the small diameter pipe that was included as rate base under FERC public-utility regulation—and complicated interstate pipeline rate cases as such. Regulated systems subject to cost-based tariffs composed one-third of the market, which left most of the market as nonregulated competition. Regulated ratemaking also cross-subsidized poorer wells at the expense of lower-cost production.

Should FERC continue such regulation post–Order No. 636—given that gathering systems were being unbundled by their regulated pipeline owners? After all, nonaffiliated gathering was not regulated from Washington. To address these questions, FERC initiated a rulemaking in 1993.

“The threat of federal regulation posed by the ‘regulatory string’ with respect to affiliated gatherers places them at a competitive disadvantage vis-à-vis non-regulated competitors,” Enron pleaded in the rulemaking. Other interstates with regulated gathering, represented by the Interstate Natural Gas Association of America (INGAA), which Enron’s Rich Kinder happened to chair at the time, sought parity and entrepreneurial freedom.

Producers, independents and majors alike, lobbied for the status quo: FERC-established rate maximums. “Gathering competition at many wells is illusory,” the chairman of the Independent Petroleum Association of America (IPAA) told FERC. Representatives from Conoco, Amoco, Anadarko, and the NGSA were opposed to gathering decontrol and even existing light-handed regulation.

The ruling came in May 1994. “The Commission will not regulate gathering facilities if a pipeline applies to ‘spin-down’ those facilities to a corporate affiliate or ‘spin-off’ those facilities to another company.” Philosophized one FERC commissioner: “We would be in error if we overregulated that sector of the industry.” Transition rules were set in place, and FERC passed jurisdiction to state energy regulators to step in as necessary.

This nod to free markets was a victory for interstates and for Enron. “We applaud the Commission for taking a very, very balanced approach,” stated Stan Horton.” There were safety nets, he noted, and “the abuse the Commission is worried about does not exist here at Enron.” Producers, after all, were customers; without supply, and good relations going forward, there could be no sales.

It was time to spin down or spin off gathering.

“Our internal analysis, coupled with unsolicited offers from interested parties,” stated Horton several months later, “indicates that the gathering assets on Transwestern Pipeline and Northern Natural gas may be more valuable to others.” Sales ensued, which reduced the mileage of Transwestern and Northern Natural by 28 percent and 40 percent, respectively. Cash in the door—the interstates had done it again for Enron.

But Enron’s gathering moves did not escape the long arm of government. The Federal Trade Commission intervened against a gathering system sale to Phillips Petroleum, requiring Enron to exclude one-third of a proposed 2,300-mile transaction in the Texas-Oklahoma Anadarko area. And Texas, among other states (including Oklahoma and Kansas), would assert jurisdiction and set up a complaint procedure for producers who felt discriminated against or abused by a gatherer through either rates or terms of service. Such light-handed regulation, however, was a far cry from the prior rate-based regulation for what had been part of interstate pipeline operations.

Low-Price Profitability

“Prosperity at home and abroad” was EOG’s message entering 1994. International operations were beginning to contribute, but North America’s seven district offices were the moneymakers. The most activity was in Big Piney (Wyoming), with other divisions covering South Texas, East Texas, West Texas and New Mexico, Oklahoma, the Gulf of Mexico, and Canada.²⁵ Natural gas accounted for 93 percent of reserves, although the company dropped its former tag line, America’s natural gas play, because of growing international ambitions.

The mini-gas-price recovery of 1993 reversed in 1994, with average wellhead revenue falling 16 percent to $1.62 per thousand cubic feet, prompting voluntary shut-ins (as much as 25 percent of EOG’s deliverability) and a capital reallocation away from infill drilling towards reserve additions. Hedging and cost reductions, as well as (regulatory enabled) prior deals executed at premium prices, made for record earnings in 1994—and a two-for-one common stock split from the public company. Indeed, the market valuation of EOG since going public in 1989 had grown from $1.8 billion to $3.8 billion, annual compounded growth in excess of 15 percent. Total return to shareholders exceeded 100 percent, double that of S&P 500—and far, far above the 5 percent negative return for its peer group in the five years.

Reserve replacement in 1994 was 177 percent, another record. Finding costs were down to $0.88 per thousand cubic feet (Mcf). Tax benefits from grandfathered tight-sands properties added $21 million in the year, which gave EOG a 4 percent effective tax rate from its 35 percent statutory rate.²⁶

“I don’t think there is anyone in the industry who can stay with us on drilling costs,” Forrest Hoglund boasted. A report by Goldman Sachs agreed, estimating EOG’s cash operating cost per unit of energy produced far below its peer group. Improved three-dimensional models to target drilling, in addition to new applications of enhanced well-competition technology, were resulting in more gas at less expense. Enron Business told employees that drilling times fell from 24 to 17 days in one field and from 13 days to 7 in another.

With wellhead gas prices hitting a new low in 1995, EOG faced what Forrest Hoglund called “probably the toughest year in our company’s history.” EOG earnings were flat but impressive in what Hoglund called “an outstanding year.”

The self-styled “low-cost independent” had to make money in new ways: “increased crude oil and condensate products, other marketing activities including commodity price hedges, and the sale of selected oil and gas reserves and related sales.” Discretionary cash flow remained north of a half-billion dollars, and stockholder returns of nearly 30 percent for the year were more than double those of EOG’s peers.

A 20 percent fall in gas prices and voluntary curtailments of 105 MMcf/d (14 percent of EOG’s North American deliverability) shifted capital from drilling to reserve acquisition in 1995. Netted with property sales, EOG wound up the year with higher reserves, more strategic properties to existing operations, and profit—”our best acquisition year ever.” Doubled reserve replacement in the year set up the future.

EOG had a political moment during the price-stressed year. EOG wanted to turn its voluntary curtailment into a mandatory one to require its fully producing competitors to cut back too—all in the effort to buoy prices. Hoglund’s bunch wanted help from any state commission that would issue mandatory proration orders. The Oklahoma Corporation Commission (OCC) was curtailing the state’s 28,000 wells, just as EOG’s state division head Leland McVay wanted. But other producers were doing what was natural: making up with volume what they were losing on price. The OCC watched helplessly as oil states Texas, Louisiana, and Kansas chose not to prorate and increased output. Competition was hurting the prorating state, and government was not able to plug the dike as had been done in past decades with crude-oil proration in the oil states and federal oil import restrictions.

Enron cashed in on EOG’s strong stock price at year’s end, selling 31 million shares of common for $650 million, earning $367 million ($161 million after-tax). Additionally, Ken Lay and Rich Kinder told shareholders in Enron’s annual report: “Primarily, as a result of the successful completion of an EOG debt offering in December 1995, we reduced our debt to total capitalization ratio to about 40 percent and achieved a key credit rating upgrade to BBB+.”

Proceeds from EOG “will expand business opportunities at ECT and Enron Development Corp,” Lay and Kinder wrote. Forrest Hoglund welcomed “the increased liquidity in EOG stock [allowing] existing investors to significantly increase their positions while also attracting new investors.” Hoglund was Enron’s top division head, with consistent, high earnings and increasing enterprise value.

It was a story of the fishes and loaves. Prior to becoming a public company, EOG was worth an estimated $880 million to Enron. After stock sales generating $2 billion for the parent, Enron’s 53 percent retention going into 1996 was worth $1.9 billion. And these were not easy times in the oil industry. Yet Ken Lay, fussing about low prices and once (in 1991) accusing the majors of predatory pricing, had wanted more.

EOG was part of a macro story of how the industry was performing for consumers, as if led by an invisible hand. The familiar warnings that “the easy stuff has been found” or “only the high cost supplies remain” were refuted early and often at EOG and across the United States.

“New technology and smarter management are prolonging the decade-old gas glut,” Toni Mack wrote in Forbes in late 1994. “Oilmen have learned to squeeze costs, turn a profit, and produce more gas, even when prices stay low.” The resulting supply was keeping prices down, and new technology, apparently without diminishing returns, was making what had been high-cost gas into low-cost gas. The marginal cost of so-called depletable natural gas was falling, just as predicted by Julian Simon and a few others in defiance of the mainstream fixity-depletion (neo-Malthusian) view.²⁷

Information technology was replacing “dumb iron” to find natural gas. What was true at EOG was industry-wide (although Hoglund’s results were above his peer group’s). “The exploration dollars are shifting from drilling to 3-D seismic,” said one Houston drilling consultant in 1995. “Three-D seismic gives a large overall picture while drilling gives you a single data point.” Seen somewhat differently, “the reservoir will have wells drilled, produced, and eventually depleted by computer under a limitless number of varying scenarios before additional wells are actually drilled.”

Not everyone was happy. As mentioned, Forrest Hoglund asked state regulators to help prices by prorating (curtailing) output between wells and fields. Ken Lay was of two minds after being heavily criticized for his predatory-pricing insinuation against major oil companies several years before. And pugnacious Oscar Wyatt urged the Texas Railroad Commission to curtail gas production between 20 and 30 percent during peak periods to increase prices to $2.50 per MMBtu (Mcf), a 50 percent jump from then-average wellhead prices. “We have freely chosen to flood the market with a premium fuel at disaster prices,” the Coastal Corp. chairman complained about the natural order of things.

If the point of production was consumption, and if the welfare of consumers trumps that of producers, the natural gas sector was doing its job. Between 1985 and 1994, inflation-adjusted gas prices fell by more than 20 percent for LDCs and industrial customers, were steady for commercial users, and rose slightly for residential users.

There was something else. With more efficient midstream operations in the open-access era, whether at a pipeline or storage facility, less gas-production capacity got the same job done for consumers than before. (Open access was “ruining the pipeline construction business,” stated John Jennrich, tongue in cheek.) Price volatility was certainly higher for those oriented to the spot market, but that was scarcity pricing in action, and risk products were available too. “The market really works,” commented Joe Foster, formerly head of Tenneco’s production side and now head of Newfield Exploration.

“In 1996, EOG will continue its strategy of increasing shareholder value regardless of market conditions,” Hoglund wrote in the first quarter. But success would have to come without price hedges, which generated $107 million in 1995 and $54 million the year before. Open positions had been closed in anticipation of a price recovery.

EOG bet right. North American prices jumped 43 percent in 1996 to $1.92/MMBtu, which also increased volume sold with the end of voluntary curtailment. Yet net income was little changed from the year before, reflecting a $100 million drop in hedging profit compared to 1995, a large decline in property sales, a 13 percent increase in operating expenses (higher wellhead prices did that), and higher income taxes without new tax-credit-eligible gas production.²⁸ Still, higher wellhead prices were desired with every dime change at the wellhead altering cash flow by an estimated $13 million.

“EOG is stronger than ever and is committed to continuing to be a leader in the use of technological advantages and low-cost, fast-track performance to enhance future profitability,” the 1996 annual report stated. Level earnings and cash flow since 1993 masked the true progress of the company from the time it went public in 1989, as well as its robust prospects for the future. In the eight years of EOG’s public life, net income and cash flow had tripled to $543 million; deliverability had more than doubled for both gas (to 830 MMcf/d) and liquids (to 22,000 barrels per day). EOG now had an international presence. All this had caused a stock share of EOG to more than double in value since the company went public—and generate quarterly dividends from twice as much stock.

Nine consecutive years of increased proved reserves after production left the company with four trillion cubic feet (gas equivalent), a 60 percent rise from when EOG first went public. This reserve figure was 92 percent natural gas and 83 percent in North America. The debt-to-capital ratio increased to 27 percent from 20 percent, however, owing to a major increase in drilling programs in North America, India, and Trinidad.

International

Forrest Hoglund reported to Ken Lay and Rich Kinder. Enron’s board of directors controlled EOG’s board, which included Lay and Kinder. So the parent’s keen international ambition was part of EOG’s DNA. “If Enron Corp. is to become a natural gas major,” Hoglund stated in 1994, “EOG must expand its exploration and production expertise globally.”

EOG’s international entreaties were good talk for investors and the parent. The philosophy was to pursue “selected conventional natural gas and crude oil opportunities outside of North America … particularly where synergies in natural gas transportation, processing, and power generation can be optimized with other Enron affiliated companies.”

Little came of discussions, agreements, tract purchases, or drilling undertaken in 12 countries: Australia, China, Egypt, France, Kazakhstan, offshore Malaysia, Russia, South Sumatra, Syria, UK North Sea, Uzbekistan, and Venezuela.²⁹ Much-anticipated LNG projects in Qatar and Mozambique with parent Enron did not reach commercialization either.

The story was different in Trinidad, where fast-track production began in 1993. Production of 63 MMcf/d in 1994 reached 124 MMcf/d in 1996, accounting for 15 percent of EOG’s total. Trinidad exceeded volumes generated out of EOG’s Calgary (Canada) division, a niche play for many years because of low gas prices and limited transmission access.³⁰

Joe McKinney and Dennis Ulak, the successive presidents of EOG’s international operations, took many long trips and laboriously negotiated with state companies, all in competition against the oil majors. Their reward was Trinidad and some oil and condensate output in India, where EOG became the first foreign-owned company to win drilling rights. The plan for the world’s “first low-cost, fast-track exploration and production company” was to double the percentage of foreign production to 25–30 percent of EOG’s total. As it would turn out, in 1999, the year that Enron Oil & Gas split from Enron to become EOG Resources, the percentage outside North America was half of that, comprising Trinidad and not much more.

Forrest Hoglund often spoke of EOG’s challenge to overcome the “political or cultural environment” in distant lands, no matter how hydrocarbon rich they might be. Hoglund was wary of political risk. Who could forget the Peruvian nationalization of 1985, which Enron finally settled in 1993? EOG’s philosophy was “layering of moderate risk growth potential outside North America on top the company’s steady North America growth profile.” Trinidad, EOG’s international bell cow, in fact, was made risk tolerable by a $100 million insurance policy courtesy of the US taxpayer-funded Overseas Private Investment Corporation (OPIC).

In India, a $200 million OPIC policy was secured as part of EOG’s $1.1 billion offshore Bombay project, whose production was forecast to reach 280 MMcf/d in several years (it would turn out to be much less).³¹ But in 1996, it was all-go with the Panna and Mukta oil fields and the Tapti natural gas play with drilling platforms and seismic surveys.

Mark Papa Joins In

Chairman, President, and CEO Forrest Hoglund was a man to keep. His original five-year contract was renewed in 1992 for three years. With a year to go on his second contract, the high performer was inked through 1998. Very few of EOG’s 800 employees were anything but happy to retain their affable leader.

“Substantially all of Mr. Hoglund’s future compensation in excess of his base salary is at risk and tied to the performance of Company’s Common Stock,” EOG reported to shareholders. Indeed, Hoglund eschewed raises and monetary bonuses in his contract. Incentives, not base pay, got Hoglund to Enron, and incentives, now totaling several million shares of stock, were keeping him there. Enron’s stock price was rising more than EOG’s, thanks to Enron Gas Services’ valuation in particular—a good thing for retaining top executives such as Forrest Hoglund.

A stock sale in 1994 produced a $19 million compensation year for EOG’s leader, which was tops for Houston’s entire business community. “There’s not a CEO of any major oil company in the country that made nearly that much,” Ken Lay gushed. But it was well deserved, Lay explained, with EOG’s 15 percent rate of return dwarfing the 5 percent typical of many of its competitors.

The Letter to Stockholders in the 1996 annual report pictured two executives, not just Forrest Hoglund as before. EOG’s new president was Mark G. Papa, who had been president of EOG’s North American operations, and who retained his old title alongside his new one. Hoglund, now 63, had chosen his heir apparent.

The 50-year-old Papa had been with EOG since its inception and with EOG-predecessor Belco Petroleum since 1981. The engineer began his career in the field and then at headquarters with Conoco in Corpus Christi. After several years in Dubai, and having gained an MBA from the University of Houston, Papa joined Belco and in two years was named vice president of drilling and operations. At EOG, he was Senior Vice President–Operations before heading the company’s North American operations, which encompassed onshore and offshore operations in the United States and Canada.

It would be Papa who succeeded Hoglund as CEO in 1999, the year that the two negotiated a full split from Enron. Papa would go on to build the renamed EOG Resources Inc. into one of the very top oil and gas independents and financial performers, until retiring in 2013.³²

Enron redeployed its EOG proceeds to international and to gas marketing, the start-up businesses that Lay saw as crucial in the mid-1990s. EOG stock selldowns gave Enron cash during vulnerable times. But more than this, Forrest Hoglund and EOG were a model for Enron: a conservative company with a much lower tolerance for risk and better cost controls than its parent.

While going its own way from the parent, EOG had richly benefitted from “four mutual synergies: product development and marketing; multiple international presences; tax credit utilization; and financial flexibility.” EOG, too, had been the physical backup (the hedge) for early gas trading by John Esslinger’s Enron Gas Marketing.

Price-rich EOG gas contracts pursuant to Enron’s PURPA-driven power plants, in addition to the tight-sands tax credit, were part of this synergy. Upstream, as in the midstream and downstream, special government favor was a major theme of Enron’s rise to preeminence.