NEWS U.S. refiners home in on profits amid near term uncertainties

This Giant Industries Inc. sprawling truck stop is nestled in the company's profitable refining/marketing niche in Northwest New Mexico. That's Giant's Ciniza refinery in the background at right, just 1/2 mile from the station's pumps. Photo courtesy of Giant Industries.

Refiners in the U.S. are struggling for profits in an economic game stacked against them by long term fundamentals and near term uncertainty.

Chief among the long term factors are stiff environmental mandates in the U.S., mostly stemming from 1990 amendments to the Clean Air Act (CAA). They have heaped capital costs on the refining industry at a time of relatively flat products demand.

By implementing massive capital spending programs in this decade, refiners have met and surpassed plant emission goals, while retooling to produce a new generation of cleaner burning fuels.

But demand and prices for reformulated gasoline (RFG) has been unpredictable, as several U.S. regions first voluntarily agreed to join, then opted out of RFG programs. Similarly, demand for low sulfur diesel has not generated the premium expected when refiners began preparing to produce it.

The fact that U.S. refiners still can produce more refined products than are needed on domestic markets dampens the outlook for significantly higher prices.

Evidence shows that U.S. refiners for the most part have maintained positive refining margins. But impaired economically by recent capital requirements and generally flat products markets, few have used traditional processing strategies, based mostly on building fixed assets, either to boost capacities by eliminating bottlenecks or to produce slates of higher value products by reconfiguring processing units.

Rather, most U.S. refiners are making ends meet by micromanaging day to day operations, closely monitoring crude and products markets, and trying to align the two.

The latter business strategies are effective when refiners can anticipate market opportunities and are positioned to take advantage of them. In an industry where market balance can change with the next news report, each strategic decision can have unexpected results.

Despite refiners' limitations, U.S. refining margins this year through May appeared much stronger than in first half 1995. Some say that shows refiners are learning to deal with the more volatile forces influencing U.S. crude and refined products markets.

Speed and transparency

Greater transparency of crude and products markets has become a key tool for U.S. refiners trying to capture short lived opportunities. Yet the broad, rapid stream of refining information, in some instances, also adds market volatility.

Calvin Cobb, president of consulting company Wright Killen & Co., Houston, says the proliferation of computerized price data has transformed U.S. refining markets. In past decades, prices in some parts of the country could be higher for days before competitors noticed and started sending product into the region to meet the shortage.

"Price discovery today is instantaneous," Cobb said. "That has a big effect on business because it affects how people manage risk."

In short, refiners, traders, and marketers not only can see market fluctuations quickly but also can react quickly. Such rapid reactions by many players can reverse market trends, adding to volatility even when traditional measures of the market are within ranges that in the past would have signaled stability.

Cobb says volatility on U.S. markets, as shown in monthly margin data of the past several years, indicates that some refiners have derived profits for an entire year in just a few months of healthy margins. That means it has become more important for a refiner to decide on the right product slate at the right time, when margins are widest.

"If a refiner happens to be down for an unscheduled turnaround 2 or 3 weeks out of 4 or 5 good weeks, that essentially can destroy a whole year's profitability," Cobb said. "So refiners are much more attuned to matching product slates to the most favorable markets and making sure their refineries are running smoothly when the margins are at a peak."

Lack of stabilizing forces

Cobb attributes much of recent U.S. refining volatility to a lack of "stabilizing driving forces."

Demand for products is relatively flat, increasing at rates no more rapid than estimated economic growth. New technology is entering the marketplace in a way that hasn't demanded higher prices to support it. And the industry has a large group of refiners competing nationally and regionally, as opposed to a few

Conversely, there is a long list of short term variables, each moving independently, that govern the U.S. refining industry's economic stability. Among them are world crude prices, world and U.S. economies, weather, products imports, futures markets, refinery operating problems, and operating strategies.

"These factors are at work all the time, and sometimes they're not all trending in the same direction," Cobb said. "Some can be affecting margins positively and some negatively."

The response of world crude oil prices to the latest reports of Iraq's standing in crude oil markets is an example of how a short term factor can increase refining volatility. Since the Persian Gulf war in 1990-91, Iraq's in-again, out-again outlook for market status has whipsawed U.S. refiners who want to avoid big inventories of crude and escape a possible price collapse when Iraq finally returns.

"A news story one day might report the United Nations sanctions won't be lifted because Iraq still is in violation of weapons issues," Cobb said. "That sends prices up. Three days later, another news story says something else, and prices go down.

"If you're a refiner, you don't want to be buying crude on the day it costs $2/bbl more than it will 3 days later."

Under normal circumstances, the price of crude doesn't necessarily affect refining margins. Refining margins can be positive whether the price of crude is high or low.

"But refiners want to avoid being caught in a change of crude price," Cobb said. "If a refiner has a big inventory of high priced crude and crude prices fall out from under that, the street price of gasoline typically falls quickly with crude prices. Then he has to work off an expensive inventory of crude, and margins go way down."

The reverse also can occur, as it did earlier this year, when crude prices rose unexpectedly when U.S. refiners were holding low inventories of low priced crude. As crude prices shot up, gasoline pump prices followed, and for a short time refiners made a lot of money processing low priced crude and selling gasoline into high priced markets.

That good fortune soon ended, however, when refiners were forced to replace depleted low cost crude stocks with high priced supplies.

Given the varying news about Iraq, U.S. refiners still want to maintain the smallest volume of crude in inventory they need to operate.

"They don't want to get caught on the wrong side of the deal," Cobb said.

When forces align

The recent runup in U.S. gasoline prices shows the extent to which unexpected alignment of several independent market forces can trigger price volatility.

Philip K. Verleger Jr., writing in the April 1996 petroleum economics newsletter of Charles River Associates Inc., Washington, says the price spike resulted from alignment of eight market factors that "created a witches brew of price volatility, high spot prices, high retail prices at times, and an absolutely impossible business climate."

Low crude oil inventories, unexpected refinery outages in California, and emtremely cold weather contributed to the witches brew. But foremost among the forces, in Verleger's view, was government environmental rules, especially introduction of RFG and attendant distribution and marketing requirements.

However admirable the government's push for a cleaner environment, Verleger says, RFG rules removed flexibility from the petroleum distribution system by requiring each clean gasoline formulation to be segregated. Refiners had to adjust distribution strategies to assure that motorists in each region failing to meet CAA environmental standards could buy the oxygenated or reformulated gasoline prescribed to help correct deficiencies.

Refiners for many years have been trying to stretch working capital, in part by minimizing crude oil and products stocks.

Implementing RFG requirements forced refiners to maintain more types of gasoline in inventory, tying up more storage capacity. Despite the need for U.S. refiners to keep more grades of gasoline on hand, Verleger estimates U.S. gasoline stocks in first quarter 1996 were 2-6% lower than a year earlier and substantially below levels in prior years.

In addition, coming as they did at a time when no one wanted to be caught with excessive volumes of high cost crude in inventory, the RFG rules placed still more pressure on refiners to minimize crude oil stocks.

Against that backdrop, several West Coast refineries last spring had unexpected processing disruptions, just as the California Air Resources Board (CARB) was introducing its more stringent Phase 2 RFG in the state.

"Such disruptions would have caused price changes in the past, but the effect would have been smaller because there was greater fungibility among products and larger inventories," Verleger said.

"Today, the mandated shift to a wide variety of products, combined with the higher risk of holding inventories, exacerbates the impact of refinery problems."

Because there is little chance refiners and suppliers willingly will begin building crude and products inventories soon, Verleger says, short term forces contributing most to the recent runup in U.S. gasoline prices likely will become permanent market fixtures.

Responding to markets

Recent RFG supply problems on the West Coast provided a good example of how many U.S. refiners are seizing short term opportunities to boost margins by closely watching products markets.

Amerada Hess, a big gasoline supplier on the East Coast, reportedly diverted as much as 20% of its gasoline output to customers on the West Coast.

In addition, Valero Energy Corp., San Antonio, sold about 1 million bbl of CARB spec gasoline into California. Valero shipped the supply from mid-March to mid-May in five cargos sent through the Panama Canal.

Valero earlier had positioned its Corpus Christi refinery to take advantage of such opportunities with capital outlays that today enable it to produce a gasoline stream of 100% RFG grade. About 25% of that output can be adjusted to meet CARB gasoline requirements. The complex also can produce about 21,000 b/d of oxygenate.

Despite the ability to produce RFG meeting California specifications, Valero didn't necessarily expect to take part in the distant market because of high transportation costs. Valero can ship products to the East Coast for an average cost of 3.5-4¢/gal. The cost of moving products to California runs 8-9¢/gal.

Valero official Keith Booke said, "That's a big difference, but the price got so strong on the West Coast during that timeframe we were able to netback higher refining margins serving that market than anywhere else in the country."

Valero in the 1980s began adapting its Corpus Christi refinery to fit product demand on U.S. markets.

Booke said Valero in the 1980s began reconfiguring its Corpus Christi refinery to run on residual fuel oil feedstock. The company aimed to capture bigger margins because of a price spread between resid and crude oil feedstock. Today, the plant proceeses 80,000-85,000 b/d of resid among total feedstock of about 170,000 b/d.

"It's still something that makes us different," Booke said of the company's resid feedstock strategy. "It's still a variable we keep our eye on because of the effect it has on Valero's refining profitability. But it's not the big factor it was 5 years ago."

Nevertheless, that strategy, coupled with the spring foray into West Coast gasoline markets, helped boost Valero's second quarter refining margins. The company in first quarter 1996 was able to buy resid feed at prices averaging about $1.35/bbl less than West Texas intermediate and in second quarter about $3.50/bbl less.

As a result, Booke says, Valero's refining margins were very strong in April and maintained their strength through mid-June, although the brief window of opportunity created by California's CARB RFG shortage had closed.

Dealing with volatility

As might be expected, many refiners faring best in more volatile U.S. crude and products markets are units of integrated companies with diversified downstream operations bridging transportation, marketing, distribution, petrochemicals, and retail affiliates.

Jim Dudley, senior managing director of Wright Killen's corporate financing and investment banking business, says integrating refining and gasoline retailing especially can increase cash flows because of the countercyclical nature of refining and marketing margins.

Assuming the volatility of both refining and marketing margins range from 45% to 50%, a refiner hypothetically can cut overall margin volatility in half by selling his gasoline through company owned retail outlets, lowering associated risks and costs of capital.

To capture benefits of such stability, Wright Killen advises refiners to focus on overall cash flow and not let marginal economics influence investment decisions, as in the past. Increasing capital spending to capture marginal economics won't improve results because the strategy, when duplicated throughout the refining industry, leads to surplus capacity and erosion of targeted margins, Wright Killen says.

"There should be increased emphasis on logistics and marketing to achieve increased product channel control," Dudley said. "Refining operations shouldn't be abandoned. However, many companies can benefit by reducing exposure to manufacturing and concentrating on efficient and technically competitive operations."

Wright Killen says refining cash margins for the past 8 years have remained positive, but profits have not been high enough to generate returns competitive with other investments. Increasing costs of regulation in the refining industry, whether for environmental protection, health, or safety, have forced higher costs into a business already troubled by slim margins.

Cobb says that in some years during the early 1990s, as U.S. refiners were preparing to produce RFG, some companies spent more money building and reconfiguring capital assets than they earned in revenue.

"From a shareholder's standpoint, these companies were not yielding an adequate return on money they were investing in refining," Cobb said. "Even today, although cash from operations is flowing positively, it's not generating an adequate return on that investment."

Major integrated strategies

Coastal Corp., Houston, in the past 3 years has developed a plan to maintain its U.S. refining margins and downstream profits that includes a mix of traditional capital investment strategies and extensive reshaping of processing capabilities at several of its refineries. The program is typical of options available to major integrated companies with diverse downstream business units.

Coastal included some fine tuning at its 170,000 b/cd refinery at San Nicolas, Aruba, Netherlands Antilles, part of its U.S. refining assets. Among the plan's key elements, Coastal has:

• Increased production of high value products and reduced production of residual fuel oil.

• Boosted company refining capacity 15,000 b/cd in 1995 to a total of about 375,000 b/cd to spread fixed costs over more barrels.

• Expanded petrochemical operations that use refined products as feedstock.

• Integrated refining and marketing operations with power generating projects to enable it to sell energy by the kilowatt.

• Shut down inefficient processing capacity-including operations at Pacific Refining Co. in Hercules, Calif., in June 1995-leaving only terminaling operations intact.

The company also has realigned marketing and distribution operations to take better advantage of synergies with its refineries.

To increase its emphasis on producing high value products, Coastal expanded the coking unit to 18,000 b/cd from 12,000 b/cd at its 95,000 b/cd Corpus Christi refinery. The company also installed a 31,000 b/cd delay coker at its Aruba refinery.

Coastal this year aims to boost its refining capacity another 40,000 b/cd.

Regional refiner's strategy

Regional U.S. refiners lack the breadth of options available to integrated companies for maintaining refining margins. But they can become more efficient by closely aligning downstream and marketing operations.

Giant Industries Inc., Scottsdale, Ariz., in the past year has been advancing such a realignment with a steady pace of acquisitions and divestitures in the Four Corners area of the western U.S.

Part of its strategy involves getting out of the upstream oil and gas business.

To that end, the company expects to close the sale of the last of its upstream U.S. assets by yearend, including reserves of about 8 million bbl of oil equivalent on Four Corners, Kansas, Oklahoma, and South Texas leases.

Giant, which operates the 20,800 b/cd Ciniza refinery about 100 miles west of Albuquerque, in the past year has closed these acquisitions:

• An October 1995 deal for the 16,800 b/cd Bloomfield, N.M., refinery near Farmington, N.M., which produces 10,000-11,000 b/d of gasoline, 4,000 b/d of low sulfur diesel fuel, and 1,000 b/d of jet fuel.

• A summer 1995 deal for a 170,000 bbl products terminal at Albuquerque, with throughput of about 5,000 b/d, resolving a longtime disadvantage in marketing to customers in northern New Mexico.

• An August 1995 deal for a 5,000-6,000 b/d crude gathering operation in the Bloomfield area, including about 20 trucks and several small pipelines.

The last acquisition gave Giant more crude supply control and flexibility, as well as incremental supplies.

"Now, either through pipelines or by trucking, we are in a position to control the pick up and direction of 90-95% of the crude oil we run at our two refineries," said Fred Holliger, Giant's senior vice-president and chief operating officer.

How the pieces fit

With its new configuration, Giant can coordinate activities at its Northwest New Mexico Ciniza and Bloomfield refineries, conceptually operating the plants as a single refining and marketing complex. The plants, although not physically connected, provide operational synergies stemming from better economies of scale. They allow Giant to spread operating costs over more barrels of output.

Giant this year scheduled turnarounds at each refinery about 60 days apart. Rather than having to curtail production and risk losing market share, the company was able to supply customers from either plant that was up and running.

Giant can direct regional crude feedstocks to the plant that can handle each feed's specific characteristics. Similarly, by serving from Bloomfield a big customer in northern Arizona formerly supplied by Ciniza refinery, Giant has been able to trim about 2¢/gal from its distribution costs.

Products sold from Ciniza into Northeast New Mexico markets through the Albuquerque terminal must be handled twice. But netbacks from such transactions are better than the alternative, which is to truck Ciniza products to Phoenix.

Giant also provides common carrier trucking services to other marketers in the Albuquerque area.

To capture the full value of its improved refining efficiencies, Giant maintains a program to develop retail markets that can be easily tied to its regional gathering, refining, and distribution network.

Giant sells about 30% of its gasoline and diesel fuel output through about 50 retail service stations and its truck stop and travel center. Included in the total are seven retail outlets in Northwest New Mexico the company acquired in late May from Diamond Shamrock Inc.

Boosting diesel demand

Giant built the truck stop and travel center about a decade ago at a site about 1/2 mile south of its Ciniza refinery to create a new retail outlet for its diesel fuel. A lack of diesel demand was constraining the company's ability to produce more gasoline.

"The concept was to make it a destination truck stop where people could come not just to refuel and eat, but also to rest and relax," Holliger said. "It has a mall with shops and a lot of extra facilities for truckers, including a parking lot big enough for about 400 tractor-trailers."

At the time Giant created the facility, it was pressing to sell 4,000 b/d of diesel fuel from Ciniza.

"Now," Holliger said, "month in and month out, our combined diesel sales are running about 6,000 b/d."

Because of its regional focus, Giant has avoided recent U.S. clean fuel mandates except for the requirement to produce low sulfur diesel. As a result, Holliger estimates the company's environmental compliance costs at less than $1 million.

Giant's regional gasoline markets are virtually devoid of CAA nonattainment areas. But it has benefited from CAA and CARB RFG requirements because product prices in Albuquerque are influenced by U.S. Gulf Coast prices. At the same time, CARB Phase 2 fuels now required in California influence gasoline prices in the western part of Giant's marketing area.

The combination of higher products values resulting from those factors and Giant's restructuring in 1995 helped the company maintain refining margins of about $5/bbl, Holliger said. Although weaker than in many past years, the company expects to sustain those margins in 1996.

Asset performance

Refiners holding underperforming assets are turning more to joint ventures (JVs) and other combinations with other refiners.

Cobb says refiners basically can improve results in two ways by combining assets, even though the combinations don't add new markets, new capacity, or new processing capabilities.

The most obvious gains are administrative and overhead efficiencies. Essentially, it doesn't take twice as big an organization to manage some aspects of the refining business.

More fundamental-but less apparent-benefits can accrue if each company brings some key advantages to a joint operation that mitigate or eliminate the other's disadvantages.

Advantages companies bring to a JV can include better technology, more flexible crude slate, or greater market coverage. Disadvantages might include shortages of key processing capabilities or lack of markets for certain high value refined products.

"Every company in the marketplace has certain advantages and disadvantages," Cobb said. "So if two companies can weave themselves together in a way that one's advantage offsets a disadvantage of the other, they can effectively enhance revenue and/or reduce costs."

Unprofitable assets

In recent years, some refiners have increased earnings by selling unprofitable assets.

Cobb says one U.S. refiner in the past 5-6 years boosted profits by a factor of six with a strategy that included reducing downstream assets by half.

"It was a pretty painful process. A lot of writedowns, a lot of people thrown out of work," Cobb said. "But if you took a snapshot today, it would show the net performance is much better."

Today, however, with the value of U.S. refineries at an ebb and no signs of an imminent reversal, the pain of divestitures might no longer be worth the gain.

While many refiners won't rule out selling assets as a strategic option, Cobb says that today in the U.S. it is difficult to sell a refinery for a sum of money that is meaningful.

As an alternative, a refiner always can shut down unprofitable assets.

"But most refiners in the U.S. have positive cash flows and when they shut down a given plant they're not only reducing the value of their assets, they also are reducing the amount of cash they are earning." Cobb said.

To compound the problem, Wright Killen says U.S. refiners face a valuation conundrum. Most carry refining assets on their books at values of about $4,000/b/d of capacity. Transaction data since 1981, meantime, show refiners on average have been willing to part with refining assets for slightly more than $1,200/b/d.

Worse, Wright Killen estimates the average cost of replacing 1 b/d of refining capacity in the U.S. at almost $12,000.

1996 margins

Cobb says refining margins in the U.S. this year should be stronger than in the recent past in all major U.S. refining regions, "even if the last half of the year is horrible."

By Cobb's estimates:

• Gulf Coast margins this year through May on average have been $1/bbl or more, compared with only 34¢/bbl on average last year.

• West Coast 1996 margins through May were $4-5/bbl, compared with less than $3/bbl last year.

• Midwest margins through May averaged about $2.50/bbl vs. about $1.30/bbl last year.

• East Coast margins through May have averaged about $1/bbl, still more than twice the yearlong average in 1995.

"By our estimations, they're all stronger through the first 5 months," Cobb said. "So this could be one of those situations in which margins during the first half of the year can make the whole year, whereas margins in 1995 were depressed by poor performance in the first half of the year."

Copyright 1996 Oil & Gas Journal. All Rights Reserved.