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REV: AUGUST 27, 2001
LISA MEULBROEK
Risk Management at Apache
Introduction
By March of 2001, managers at Apache Corporation, an independent oil and gas exploration and
production company, had reason to be optimistic. While oil prices had softened somewhat recently,
at $27 a barrel they were much higher than the pernicious levels of 1998, when oil bottomed out at
$11 per barrel. Apache had just closed on the acquisition of Repsol in Egypt's Western desert and,
along with its partner Shell Overseas Holdings, had also acquired Fletcher Challenge Energy, for a
combined cost of $1 billion. The value of such acquisitions, however, depended in large part on the
future prices of oil and gas. To decrease its exposure to oil and gas price volatility, Apache had
begun a limited hedging program centered mostly on its recently acquired properties. Apache’s
managers knew that hedging could create its own risks, and so it seemed prudent to re-evaluate the
success of the new program. The decision facing Apache’s managers was whether the firm should
continue hedging, and if so, should its current program be extended beyond hedging the revenues
from acquisitions?
Apache Corporation
Apache Corporation was founded in 1954 by Raymond Plank, its current Chairman and Chief
Executive Officer. Mr. Plank’s son, Roger, was the company’s current CFO, but the company was not
controlled by the Plank family, and in fact, officers and directors as a group held less than 1.25% of
the company’s common stock (see Exhibit 1-3 for Apache’s Income Statement, Balance Sheet, and
Cash Flow Statement). By 2001, Apache had evolved into a large independent oil company that
explored, developed, and produced oil and natural gas in North America, with offshore exploration
and production interests in Egypt and Australia the most important of its international regions. It
also had exploration interests in Poland, and offshore China. Under Mr. Plank’s leadership,
production had grown for 23 consecutive years, including about 28% in 2000, and a predicted 25% or
more for 2001. In 2000, some 45% of total production was North American natural gas, and Apache’s
reserves were fairly evenly split between oil and gas. Exhibit 4 shows Apache’s oil and gas revenues
and costs by country.
________________________________________________________________________________________________________________
Professor Lisa Meulbroek prepared this case with the assistance of Research Associate Puja Malhotra. HBS cases are developed solely as the basis
for class discussion. Cases are not intended to serve as endorsements, sources of primary data, or illustrations of effective or ineffective
management.
Copyright © 2001 President and Fellows of Harvard College. To order copies or request permission to reproduce materials, call 1-800-545-7685,
write Harvard Business School Publishing, Boston, MA 02163, or go to http://www.hbsp.harvard.edu. No part of this publication may be
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Apache's strategy was to maximize production and to minimize cost. Specifically, management
sought to increase oil and gas reserves, production, cash flow and earnings through a combination of
exploratory drilling, development of existing projects, and select property acquisitions. To retain
control over development, Apache preferred to operate its own properties, and was currently
operating the properties responsible for over eighty percent of its production. While its North
American operations focused on development of more mature properties (eighty percent of the
company’s proved reserves were located in North America), Apache’s international operations were
more exploration-oriented. Its strategy was to concentrate its efforts, hoping to become the dominant
operator in a region. Apache viewed its international operations as riskier than its domestic
operations: not only were the properties themselves less mature than the North American holdings,
but political risk compounded the greater geological uncertainty. Apache avoided international areas
with the most risk, such as West Africa, or territory within the former Soviet Union. Exhibit 5 shows
the results of Apache’s drilling programs in the U.S. and internationally. In addition to exploiting
Apache’s existing asset base through a combination of workovers, re-completions, and moderate risk
drilling, Apache’s managers sought out acquisitions where they could add value. This entailed
enhancing the reserves, consolidating properties, and accelerating a property’s cash flows, which
could then be used to pay down the debt incurred in purchasing the property.
Apache’s compensation program reflected its goals of maximizing production while minimizing
costs. Incentive bonuses were frequently based upon growing both reserves and production and
keeping costs low. In 2000, this meant that executives were eligible for a bonus above the target of
fifty percent of their base salaries if the company acquired or brought under its management assets
valued in excess of $1 billion while maintaining an acceptable debt-to-capitalization ratio of 45
percent or less. Apache’s long-term incentive compensation plan called for all employees to receive
additional compensation if the company achieved target stock price levels of $100, $120, and $180 by
year-end 2004. Moreover, if production per share doubled to projected levels, additional
compensation would be granted. This goal was derived from a recognition that oil and gas price
levels were outside the control of managers, but production levels were not, and so sought to reward
managers for the variables within their control.
High oil and gas prices had made the past year extraordinary in many respects. While able to
defer anywhere from 70-80% of its taxes, it was still the first year in some time that Apache had to
pay any taxes. The company had also made an unusual number of acquisitions in 2000. These
acquisitions included producing properties in Oklahoma and Texas from Repsol for $149 million,
producing properties in the Permian Basin and S. Texas for $321 million from Collins & Ware,
properties in the Gulf of Mexico from Occidental Petroleum for $321 million (plus an additional $44
spread out over the next four years), Canadian properties from Phillips Petroleum for $490 million,
and miscellaneous tactical regional acquisitions for $104 million. Together, the reserves added
through such acquisitions replaced the amount that Apache had actually produced during 2000 four
times over. As Apache moved into 2001, they had acquired over $1 billion in property by March.
Apache’s managers also anticipated spending an additional $1 billion in capital expenditures in 2001,
mostly for exploration activity. Financial flexibility was considered a critical element in the execution
of these plans, and the rating agencies had recently upgraded Apache’s rating to “A-” from “BBB+”
in recognition of their success along these lines. And, over the past two years, Apache had financed
$3.7 billion worth of acquisitions, while maintaining a debt ratio of about 40%, and interest coverage
ratio of six times. Exhibit 6 details Apache’s acquisitions and financing.
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The Oil and Gas Industry
Apache represented one of several types of independent oil companies. Very small secondary
players, the “mom and pop” companies of the oil industry, were low-tech and low-cost. Wildcatters,
another category of independent oil companies, drilled speculatively for oil, with only a limited
amount of testing involved before drilling. Apache represented a final type of independent, one
larger than the small secondaries, who managed virgin fields in addition to the more mature
properties. This category included not only Apache, but also firms such as Ocean Energy (formerly
called Seagull) and Burlington Resources. Apache was not only larger than many independent oil
companies, it also had a reputation for being technically advanced. Exhibit 7 shows Apache’s stock
price performance relative to major and secondary oil companies. Exhibit 8 compares key firm
characteristics.
As a field matured, oil production declined exponentially. Roughly one-third to one-half of oil in
a particular field was recovered via “conventional means,” at which point secondary recovery
techniques, which were more costly, were required. Secondary recovery techniques involved
pumping various substances into the ground to encourage oil to come closer to the surface. For
example, water might be used to keep up the oil pressure, enabling it to be pumped. Underground
fields were even set on fire to heat viscous oil in order to increase the oil’s fluidity and facilitate
pumping. So, as production continued for a given field, the costs of bringing the oil to the surface
increased. The continual depletion of reserves also meant that oil companies had a persistent need to
replenish those reserves.
Oil exploration and production in the U.S. and Canada had gone on longer than in most areas of
the world, making the oil fields in the U.S. and Canada the most mature fields in the world. As a
field matured, the major oil companies typically sold it to a secondary, or independent, oil company.
The smaller firms who acquired the mature fields generally had lower cost structures which allowed
them to efficiently exploit fields that the majors, with their higher cost structures could not. In part,
the lower cost structures possessed by the independent firms resulted from their leaner staffs: unlike
the major oil companies, the smaller independent firms tended not to have specialists for every type
of analysis. In purchasing a field from a major oil company, the independent also purchased the
“work” done on that field. Typically, by the time one of the independent firms purchased a field, the
major oil companies had already incurred some of the large costs, such as 3-D seismic surveys, and,
of course, the purchase price therefore reflected such work done on a field.
While many of the oil properties in the United States were mature, leading the major oil
companies to reduce their exploration and development in the United States, the same was not true
of natural gas. The United States still had a large supply of on-shore gas, and exploration and
production of natural gas continued. The stock of gas was greater than the stock of oil, and had the
advantage of being a very clean technology. Water and CO2 were the primary by-products of
burning gas, which were easier to dispose of than the nitrogen and sulfur compounds that result
from burning oil. The United States also had an extensive pipeline system that allowed for transport
of gas throughout the country. Outside the United States, though, such extensive coverage was rare,
and the ability of producers to transport gas from its source without a pipeline was limited. Efforts
were underway to ease transportation limitations by efficiently changing the state of gas to a liquid so
that it could be transported by ship, but such technology was not yet available. Oil was clearly easier
to transport, and had the additional advantages that more markets for it existed, and it was useful in
ways that gas was not (e.g. the production of plastic or fertilizer).
Hydrocarbon accumulations, however, were typically a mixture of oil and gas, because oil and gas
were co-miscible (they dissolve in each other). The amount that could dissolve was a function of
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pressure and temperature (i.e. depth), and the ratio of oil-gas in the ground was not the same as that
at the wellhead. Gas was always present in oil, and usually some liquids were dissolved in gas,
although the amounts could vary tremendously. The presence of any liquids was usually very good
for the viability of a project, as it meant a higher energy density.
Some flexibility surrounded the speed of producing oil, but physical limits tempered that
flexibility. An oil or gas reservoir could be damaged if production is too fast or too slow. The
appropriate speed was determined largely by the reservoir type (sandstone, carbonate, etc.), what
combinations of water, oil, and gas were present, and the "drive mechanism" (water drive, depletion
drive, etc.). If the reservoir was in secondary or tertiary recovery (i.e. fluid is used to force oil out of
the reservoir), flexibility in production rates would be very limited. Injection and production rates
were critical parameters for optimal secondary or tertiary recovery. The rate of gas production had
its limits, too, although in general, the rate of gas production was more flexible than that of oil
production. In addition to physical constraints on pumping speeds, competitive concerns also
affected the speed of production. The threat of a competitor with wells in an adjacent lease gave a
firm a strong incentive to maintain production, in order to prevent that competitor from draining the
firm’s own reserves. High fixed costs, state regulated maximum production limits, and contractual
issues with partners and royalty owners all had the potential to limit a company’s ability to vary
production. Apache’s general approach to production speed was to run “flat out,” pumping as
quickly as possible.
Consequences of Price Volatility
Oil and gas price changes (see Exhibit 9 for historical volatility levels) affected the production and
development of properties. When the price of oil was low, production tended to shift away from the
United States, due to its relatively high cost of producing oil. In the Gulf of Mexico, for example,
moving oil from the seafloor to the platform cost approximately $12 per barrel. In Saudi Arabia,
however, costs were much lower, on the order of $0.15 to $0.50 per barrel. During the last period of
low oil prices in 1999, many of the major oil companies considered withdrawing from the United
States altogether. Indeed, the primary remaining oil interest the majors had in the United States was
in deep-water drilling in the Gulf of Mexico. Deep-water drilling had large fixed costs, with
production platforms costing roughly one billion dollars to establish, and the risks were considerably
higher. In a graphic illustration of the risks involved in offshore production, the world’s largest oil
platform had recently tipped over sideways and submerged into the ocean off of Brazil. Oil prices
also affected the costs and the availability of drilling rigs. When prices were high, rigs were booked
up to 18 months in advance, whereas when prices were low, the oil companies cut their capital
expenditures, leaving many rigs tied up at docks, rusting.
As oil prices dropped, firms had to decide whether to “shut in” a well. Closing a well was to a
certain extent a one-way option. Closing could damage the reservoir; starting up production again
could be difficult. Shutting in eliminated the fixed cost of maintaining the well’s structure at the
expense of requiring large start-up costs to re-drill the well again. Drilling on-shore cost perhaps one
or two million dollars per well, with each field comprising in the range of twenty to fifty wells.
Reservoir engineers and geologists could also be laid off to reduce fixed costs, and platform workers
could also be dismissed, keeping only a skeleton crew remaining to run the rig. Of course, firing such
personnel often meant loosing a great deal of institutional knowledge about a particular reservoir.
Nonetheless, the petroleum business was notorious for large layoffs in times of low oil prices,
followed by the addition of many employees when oil prices are high. Moreover, oil and gas
producers had a reputation for mis-using the increased cash flows that resulted from higher oil
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prices, spending too much money drilling wells, or paying too much for properties when oil prices
were high.
There was a sense among Apache’s managers that the hiring and firing cycles were extremely
costly to the firms, a view supported by some outside observers. Speaking to the importance of what
he termed “specific knowledge,” that is, the knowledge of local geological and business conditions,
Jeff Sandefer from Sandefer Capital, a fund investing in energy companies, noted that:
The people that tend to win in this business are the old timers that have played in one
region—say, the same county in North Central Texas—for 20 or 30 years. The large companies
tend to move people around and, as a result, they fail to develop specific knowledge. When
you move from one geographic basin to another—from, say, a tertiary recovery CO2 flood in
West Texas to the deep drilled wells in the Rocky Mountains—you enter a new world;
everything changes. But the guys who have been in the same place for 30 years have seen all
the ups and downs. They know how the service companies cycle in and out. They understand
the operating leverage inherent in the assets. They understand that this little squiggle on the
log here means one thing here, and, if you move over four miles, the same little squiggle means
something else.1
Oil price volatility also had the potential to disrupt acquisitions and development of current
assets. The low prices of oil in 1999, for example, disrupted Anadarko Petroleum’s (another
independent oil producer) five-year development and production plan. This plan had called for
spending more than its expected cash flow, and funding the shortfall with debt. As oil and gas prices
dropped, and the company’s cash flows dropped below forecasted levels, Anadarko’s managers felt
the company’s leverage had become too high, and were forced to sell $100 million in assets, and issue
$240 million in equity to put the company back on track.2 Exhibits 10 and 11 show the relation
between oil and gas producers stock returns and oil and gas price changes.
Risk Management in the Oil Industry
Oil futures had been traded as early as the 1800s, only to all but disappear until the New York
Mercantile Exchange (NYMEX) introduced a futures contract on heating oil in 1978, eventually
followed by a futures contract on crude oil in 1983.3 Much of the market in energy derivatives, did
not occur on an exchange at all, taking place instead in the “over-the-counter” market, where the
counterparts to the trade arranged the trade privately without an exchange to intermediate. One
advantage of the rapidly developing markets in energy derivatives was that they substantially
lowered trading costs. While a producer who signed a long-term fixed-price contract with a
consumer for a physical commodity was functionally accomplishing the same kind of risk transfer,
the search costs of finding an appropriate counterpart in these “one-off” contracts were high. Of
1 “Energy Derivatives and the Transformation of the U.S. Corporate Energy Sector,” in the Journal of Applied Corporate Finance,
Volume 13, Number 4, Winter 2001, pp. 50-75.
2 “The Rising Tide Hasn’t Lifted All Boats – Yet,” in Energy Conference Review, Merrill Lynch Report, November 9, 1999. Note
that even when oil prices picked up, Anadarko continued to spend more than its cash flows, as their goal was to more than
replace their reserves. Anadarko’s increases in reserves had more than fully replaced its annual production for the past 18
years.
3 Much of the background information in this section is drawn from “Energy Derivatives and the Transformation of the U.S.
Corporate Energy Sector,” in the Journal of Applied Corporate Finance, Volume 13, Number 4, Winter 2001, pp. 50-75.
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course, standardized contracts had disadvantages too: they exposed participants to “basis risk.”
Standardized contracts were priced for delivery at a specific point; in the case of gas, this meant the
Henry Hub in Louisiana. The company entering the contract was responsible for getting the gas to
the Henry Hub, meaning that this portion of the cost would be unhedged even after entering into
hedging contracts. Apache’s exposure to this basis risk had proved costly in the past when it found
itself unable to ship gas to the Henry Hub to settle contracts, but basis risk, at least in theory, could be
minimized through over-the-counter contracts with dealers such as Goldman Sachs.
Embracing these new financial instruments were some firms, like Enron, who had completely
transformed their business operations through the use of derivatives. Gene Humphrey, Chairman
and CEO of Enron’s Investment Partners subsidiary, explained that Enron used “…financial
techniques such as hedging with derivatives to reduce our need for financial capital, while making
the most of our intellectual capital....” Echoing this endorsement, John McCormack of Stern Stewart’s
energy and real options practice noted that:
Companies that hedge major price risks, all other things equal, reduce the amount of equity
they need to support their operations. And, to the extent that it increases the amount of
leverage a company can support with a high degree of confidence, corporate hedging can
reduce the company’s overall cost of capital. Moreover, for companies that need to raise
outside capital, I would argue that hedging has the potential to increase their access to capital
markets, and to improve the terms on which they raise that capital.4
Humphrey of Enron argued for the importance of managing risk for independent exploration and
production companies. He noted that in the late ‘80’s and early ‘90’s low prices created a “credit
crunch,” making it difficult for the firms to get access to capital. Enron offered these firms
“volumetric production payments” (VPP’s), where the firm received funding upfront for future
production, and in return promised to deliver a fixed volume of product in the future. Humphrey
was convinced that “…there were several companies we did this with that I think would otherwise
have gone under because they didn’t have any other sources of capital.”5
Ron Erd, Vice President of Southern Company Energy Marketing, another supplier of structured
derivative products, offered that “…with the help of derivatives… industrial companies can choose
to focus on managing just those risks where they have a comparative advantage. But, in those cases
where other players have a clear comparative advantage, the company can transfer those risks to
those other players, whether they be other industrials, or financial players.”6
Supporters of hedging also pointed to the ability of hedging to facilitate better performance
evaluation, allowing investors to evaluate the firm’s overall performance, and also permitting the
firm to evaluate the performance of specific divisions or projects. As explained by Sheridan Titman,
Director of the University of Texas’s Center for Energy Finance Research and Education, and
Professor of Finance:
4 “Energy Derivatives and the Transformation of the U.S. Corporate Energy Sector,” in the Journal of Applied Corporate Finance,
Volume 13, Number 4, Winter 2001, pp. 50-75.
5 Ibid.
6 Ibid.
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For companies that are able to manage major price risks it’s much easier to evaluate people
based upon output rather than on input…because a lot of the components of output that
basically add noise to our measures of managerial performance can be hedged away. For
example, if someone is responsible for managing the New Mexican oil region, his performance
no longer has to be subject to oil price risk. With that source of volatility eliminated, what
remains is a much more reliable performance measure—one that does a better job of reflecting
the manager’s performance with respect to those factors over which he exercises a large degree
of control.7
Some proponents of hedging believed that the increased ability to evaluate performance was
especially useful in the oil industry, where the historic emphasis tended to first center on how much
oil had been produced, and then on how much of a firm’s reserves had been replaced, rather than on
the value created (or not) through those actions.
Finally, some companies viewed risk management as an essential element of their business
strategy. Statoil, Norway’s state-owned oil company, was reported to have one of the world’s most
sophisticated and effective enterprise-wide risk management practices outside those found in
financial firms. Petter Kapstad, Statoil’s controller, explained that the firm viewed risk management
as essential to their business operations: “Our risk management system is really just the result of an
investigation into our business and the best way to manage it. We didn’t suddenly say one day: ‘We
want an enterprise-wide risk management system.’ We just decided that we wanted to look closely
at our business. It can never be a negative to have a better understanding of the business you run.”8
Despite these encomiums, skepticism about the usefulness and desirability of transferring risk
away from the oil companies remained. After all, risk reduction was costly; it consumed
management time and resources. Moreover, companies that sold production forward would be
forgoing the upside if prices were to increase, and firms that used options to “retain the upside”
would pay a premium up front to get rid of the downside risk. In the end, it was far from clear that
transferring risk created value, and, for the most part, the major integrated oil companies had shown
little interest in using derivatives to manage their price exposures. Some analysts supported this
practice, noting that investors buy shares in such companies for the exposure to oil risk, making
hedging counter-productive. Tom Dougherty, general manager of risk management at Texaco,
explained that Texaco’s share price had increased more than twenty percent last summer as oil prices
increased. If Texaco had hedged its oil price exposure, that increase in shareholder value would have
never occurred.9 Finally, hedging could be risky simply because it had not become “standard
practice” in much of the industry. Thus, if prices increased, a company that hedged was likely to find
itself relatively alone when its competitors were raking in profits, and if prices decreased, profits
might be low, but at least unhedged companies had plenty of company (Exhibit 12 shows hedges-inplace for years 2000 and 2001 for many firms). While not yet widespread in the oil and gas business,
hedging did occur in some other industries facing similar price fluctuations. In fact, the airlines had
adopted hedging strategies that resembled some of Apache’ s option-based hedging practices.
7 Ibid., p. 68.
8 “Statoil steers a steady course,” Enterprise-Wide Risk Management Special Report in Risk Magazine, December 2000, p. S6.
9 “Who needs firm-wide risk?” Enterprise-Wide Risk Management Special Report in Risk Magazine, December 2000, p. S3.
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Apache's Hedging Practices
Apache had recently begun the practice of hedging the expected production from its new
acquisitions. The price of natural gas on the futures market had been high relative to historical levels,
and in fact the futures prices exceeded the market price for reserves in the ground. Conventional
wisdom suggested that acquisitions during a time of high prices should be avoided as they generally
seemed to result in “buying high, selling low,” a less-than-optimal strategy. In fact, many of
Apache’s competitors had remained on the sidelines, avoiding acquisitions, because they believed
prices would not stay at such high levels. Apache’s view was that the current environment offered
the company the opportunity to negotiate the purchase of excellent properties, at potentially
attractive prices. Through hedging, Apache’s managers locked in these high gas prices. For example,
the prior August Apache had bought Occidental Petroleum’s reserves in several Gulf of Mexico fields
for $365 million. This price amounted to roughly $1.12 per thousand cubic feet of reserves. Apache
used “costless collars” (i.e. selling a call, buying a put with the proceeds from the call used to pay for
the put) to lock in a price floor of $3.50, while preserving the upside up to $5.26 per thousand cubic
feet. These hedges concentrated on the expected production over the next two to three years
(markets were liquid to perhaps five years out, sometimes more).10
Regarding that acquisition, Apache’s controller, Thomas Mitchell, further explained that “any
hedging strategy must be grounded in a market view; at Apache, our near-term view is generally
bullish. We believe that oil prices reflect renewed discipline by the OPEC nations that have
successfully reduced inventories in the world system during a period of strong demand… We also
believe the North American natural gas market is in a period of supply shortfall, which is the result
of the collapse in the industry’s gas well drilling activity during 1998 and early 1999.” Apache’s CFO,
Roger Plank, reckoned that even after the cost of extraction, the acquisition in combination with its
hedging strategy assured Apache a “double-digit” return. In Plank’s view, the collars provided good
protection against a potential downturn, but they left upside potential consistent with Apache’s view
of a tight market. Through hedging, Plank thought Apache was able to purchase high quality
properties at low cash flow multiples. This strategy, however, was not itself without risk: Apache
would forgo any additional profits that would accrue if prices were to increase too much. Indeed, by
March of 2001, gas prices had continued to rise above Apache’s call price of $5.26.11 Yet, as Plank
noted, Apache’s hedging program had yielded projected production levels in 2001 that exceeded the
prior year’s production by at least 25%. Because U.S. production was shrinking, prices remained
robust, leading to record financial results. Aside from the obvious financial benefits, Apache’s
managers thought hedging had benefited the firm in a more subtle way: hedging contributed to the
firm’s credibility in the acquisition process. The ability to carry through on a deal quickly, combined
with its reputation of always closing on a deal, gave Apache a big advantage in the acquisitions
market. By adding to the firm’s financial flexibility, hedging increased Apache’s ability to execute
quickly.
Apache was not alone in its practice of hedging the production of newly-acquired companies:
Newfield Exploration had recently used the same approach in an acquisition. Apache’s efforts had
brought both accolades and disapprobation. In announcing its upgrade of Apache’s debt to A-,
Standard & Poor’s (S&P) had cited Apache’s hedging practices along with its overall conservative
financial practices. S&P concluded that “even if prices were to revert to very depressed levels, the
10 As far as financing the acquisition itself, Apache subsequently issued equity to bring its debt to total capitalization ratio
down to 39% (Apache had a long history of re-balancing its capital structure following acquisitions).
11 Apache’s hedging was limited to acquisitions. Explained Roger Plank, "Our approach is to leave our base unhedged, but to
use hedges on acquisitions to build the company. Acquisition economics are hypersensitive in the first few years of investment,
so we try to protect through a period of payout."
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company is likely to maintain adequate coverage of fixed charges and capital expenditures needed to
replace production. Financial flexibility remains strong, given the company’s access to $1.5 billion of
available bank credit lines, a flexible capital spending budget, salable assets, and its very extended
debt maturity schedule.”12 CFO Magazine simply noted that “Apache has a reputation for solid
financial management.”13 Even investors who had initially been opposed to any hedging seemed to
support Apache’s hedging strategy.
Yet, some oil and gas producers had made very deliberate decisions to avoid hedging. EOG
Resources, a natural gas producer spun off of Enron, decided in 1999 that the industry was entering a
sustained tight gas market, and therefore elected to be entirely unhedged towards natural gas prices
going forward.14 And hedging was not the only risk management strategy available. Managers at
Talisman Energy, the largest Canadian-based oil and gas producer, thought that the company’s size
gave it liquidity and stability, and diversified its technology risk. Size also gave it the strength to
undertake many projects at the same time.15 The latest down cycle in energy prices had convinced
some companies of the value of maintaining a strong balance sheet. Union Pacific Resources, for
example, recognized that without hedging, its large cash acquisitions created a dangerous degree of
exposure, and began concentrated efforts to de-lever to restore financial flexibility.16 Other
companies viewed technology and low costs as a way to manage risk exposure. Vastar Resources, for
instance, had done well during 1999’s downturn by keeping its costs down. Vastar chose projects
near existing infrastructures to reduce startup time and costs, and management believed that this
practice was integral to their high exploration success rate. They also viewed better and more
experienced interpretation of 3D-seismics as a way to lower drilling risk.17
The Decision
Apache’s managers wanted to chart a well-defined risk management strategy. Before continuing
any further with hedging, they wanted to establish whether transferring risk from Apache’s
shareholders to some other company or investor at a market-determined price would create value for
Apache’s shareholders. And if managing risk turned out to maximize shareholder value, they
wondered how, if at all, operational methods to manage risk could be used to supplement or
substitute for hedging, and whether their own views on the future price path of oil and gas should
shape their strategy. Finally, they were concerned about how to adjust their use of derivatives in the
face of a new accounting requirement, FAS 133. FAS 133, which had become effective on January 1,
2001, required companies to mark-to-market all their derivative positions, and to report gains and
losses on their income statement, without reporting any offsetting changes in the value of the
underlying asset that is being hedged. Ironically, the end result for many firms might be that hedging
actually created, rather than dampened, apparent volatility in reported earnings.
12 Standard & Poor’s CreditWire, Jan. 26, 2001.
13 Tim Reason, CFO Magazine, April 2001, p. 36.
14 “The Rising Tide Hasn’t Lifted All Boats – Yet,” in Energy Conference Review, Merrill Lynch Report, November 9, 1999.
15 Ibid.
16 Ibid.
17 Ibid.
9
This document is authorized for use only by CONSORZIO MIB Trieste School of Management in 2024.
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201-113
Exhibit 1
Risk Management at Apache
Apache Income Statement ($ thousands)
12/31/2000
12/31/1999
12/31/1998
12/31/1997a
12/31/1996a
$2,290,759
$1,143,946
$761,188
$983,773
$833,164
196,951
142,868
REVENUES:
Oil and gas production revenues
Gathering, processing and marketing revenues
Equity in income (loss) of affiliates
Other revenues
862
(7,717)
153
(1,558)
(1,683)
(2,768)
(281)
2,454
840
1,400
2,283,904
1,146,553
760,470
1,176,273
977,151
583,546
442,844
382,807
381,416
315,144
OPERATING EXPENSES:
Depreciation, depletion and amortization:
Recurring
Additional
--
Lease operating costs
Severance and other taxes
--
243,178
255,251
190,576
182,138
59,173
32,400
28,642
--
--
Operating costs
231,370
225,527
Gathering, processing and marketing costs
194,279
138,768
Administrative, selling and other
75,615
53,894
40,731
38,243
35,911
168,121
132,986
119,703
105,148
89,829
Financing costs:
Interest expense
Amortization of deferred loan costs
Capitalized interest
Interest income
2,726
4,854
4,496
6,438
5,118
(62,000)
(53,231)
(49,279)
(36,493)
(30,712)
(2,209)
1,080,223
INCOME (LOSS) BEFORE INCOME TAXES
Provision (benefit) for income taxes
INCOME (LOSS) BEFORE CHANGE IN
ACCOUNTING PRINCIPLE
Cumulative effect of change in accounting principle,
net of income tax
NET INCOME (LOSS)
Preferred stock dividends
INCOME (LOSS) ATTRIBUTABLE TO COMMON
STOCK
(2,343)
(4,383)
(2,768)
(2,629)
801,980
948,033
917,633
776,956
1,203,681
344,573
(187,563)
258,640
200,195
483,086
143,718
(58,176)
103,744
78,768
720,595
200,855
(129,387)
154,896
121,427
(7,539)
--
-(129,387)
-154,896
--
713,056
200,855
19,988
14,449
$693,068
$186,406
($131,391)
$154,896
$121,427
$5.94
$1.73
($1.34)
$1.71
$1.42
2,004
--
121,427
--
BASIC NET INCOME (LOSS) PER COMMON SHARE:
Before change in accounting principle
Cumulative effect of change in accounting principle
-0.07
--
--
--
$5.87
$1.73
($1.34)
$1.71
$1.42
Before change in accounting principle
$5.73
$1.72
($1.34)
$1.65
$1.38
Cumulative effect of change in accounting principle
(0.06)
DILUTED NET INCOME (LOSS) PER COMMON
SHARE:
$5.67
-$1.72
-($1.34)
-$1.65
$1.38
Source: Apache 2000 10-K for years 1998-2000 and Apache 1998 10-K for years 1996-1997.
a
In 2000, change in accounting principle to carry crude oil inventories at cost not market value in accordance with SEC
announcements.
10
This document is authorized for use only by CONSORZIO MIB Trieste School of Management in 2024.
For the exclusive use of C. MIB Trieste School of Management, 2024.
Risk Management at Apache
Exhibit 2
201-113
Apache Consolidated Balance Sheet ($ thousands)
12/31/00
12/31/99
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Receivables
37,173
13,171
506,723
259,530
Inventories
54,764
45,113
Advances to oil and gas ventures and other
31,360
25,254
630,020
343,068
9,423,922
7,409,787
PROPERTY AND EQUIPMENT: (Oil and gas, on the basis of full cost accounting:)
Proved properties
Unproved properties and properties under development, not being amortized
977,491
869,108
Gas gathering, transmission and processing facilities
573,621
442,437
Other
Less: Accumulated depreciation, depletion and amortization
119,590
105,635
11,094,624
8,826,967
(4,282,162)
(3,711,109)
6,812,462
5,115,858
39,468
7,481,950
43,617
5,502,543
OTHER ASSETS:
Deferred charges and other
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt
Accounts payable
Accrued operating expense
25,000
6,158
259,120
148,309
23,893
18,226
143,916
101,490
Accrued compensation and benefits
34,695
22,631
Accrued interest
25,947
28,118
Other accrued expenses
40,776
11,846
553,347
336,778
2,193,258
1,879,650
Accrued exploration and development
LONG-TERM DEBT
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes
699,833
360,324
Advances from gas purchasers
153,106
180,956
Other
127,766
75,408
980,705
616,688
98,387
98,387
208,207
210,490
COMMITMENTS AND CONTINGENCIES (Note 10)
SHAREHOLDERS' EQUITY:
Preferred stock, no par value, 5,000,000 shares authorized--Series B, 5.68% Cumulative
Preferred Stock,100,000 shares issued and outstanding
Series C, 6.5% Conversion Preferred Stock, 138,482 and 140,000 shares issued and
outstanding, respectively
Common stock, $1.25 par, 215,000,000 shares authorized 126,500,776 and 116,403,013
shares issued,respectively
158,126
145,504
Paid-in capital
2,173,183
1,717,027
Retained earnings
1,226,531
558,721
Treasury stock, at cost, 2,866,028 and 2,406,549 shares, respectively
(69,562)
Accumulated other comprehensive loss
(40,232)
3,754,640
7,481,950
(52,256)
(8,446)
2,669,427
5,502,543
Source: Apache 2000 10-K
11
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201-113
Exhibit 3
Risk Management at Apache
Apache Statement of Consolidated Cash Flows ($ thousands)
12/31/00
12/31/99
12/31/98
713,056
200,855
(129,387)
Depreciation, depletion and amortization
583,546
442,844
625,985
Provision (benefit) for deferred income taxes
350,703
77,494
(81,856)
Amortization of deferred loan costs
2,726
4,854
4,496
Cumulative effect of change in accounting principle
7,539
Other
9,719
Other non-operating activities
8,251
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
-1,533
---
(387)
1,887
65,487
Changes in operating assets and liabilities, net of effects of acquisitions:
(Increase) decrease in receivables
(253,721)
(103,167)
(Increase) decrease in advances to oil and gas ventures and other
(6,167)
(15,330)
3,879
(Increase) decrease in deferred charges and other
(1,562)
(2,356)
13,238
111,841
24,912
(65,851)
45,281
26,233
(12,161)
Increase (decrease) in advances from gas purchasers
(27,850)
(24,512)
50,922
Increase (decrease) in deferred credits and noncurrent liabilities
(13,976)
5,201
Increase (decrease) in payables
Increase (decrease) in accrued expenses
NET CASH PROVIDED BY OPERATING ACTIVITIES
(5,128)
1,529,386
638,174
471,511
(1,010,528)
(591,316)
(699,509)
(19,884)
38,774
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment
Non-cash portion of net oil and gas property additions
42,934
Acquisition of Phillips properties
(490,250)
--
--
Acquisition of Occidental properties
(321,206)
--
--
Acquisition of Collins & Ware properties
(320,682)
--
--
Acquisition of Repsol properties
(118,678)
--
--
Acquisition of Shell Offshore properties
--
(687,677)
--
Acquisition of Shell Canada properties
--
(517,815)
--
Acquisition of British-Borneo interests, net of cash acquired
--
(83,590)
--
Acquisition of Novus subsidiaries, net of cash acquired
Proceeds from sales of oil and gas properties
Other, net
NET CASH USED IN INVESTING ACTIVITIES
--
(5,758)
26,271
155,226
(36,875)
(18,937)
(2,229,014) (1,769,751)
(48,499)
194,147
2,967
(512,120)
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings
Payments on long-term debt
Dividends paid
Issuance (repurchase) of preferred stock
1,125,981
1,602,871
(793,531) (1,075,821)
551,897
(556,141)
(52,945)
(42,264)
(28,204)
(2,613)
210,490
98,630
Issuance of common stock
465,306
455,381
1,240
Payments to acquire treasury stock
(17,730)
(15,603)
(21,418)
Cost of debt and equity transactions
NET CASH PROVIDED BY FINANCING ACTIVITIES
(838)
723,630
(4,843)
1,130,211
(544)
45,460
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
24,002
(1,366)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
CASH AND CASH EQUIVALENTS AT END OF YEAR
13,171
14,537
9,686
37,173
13,171
14,537
Source: Apache 2000 10-K
12
This document is authorized for use only by CONSORZIO MIB Trieste School of Management in 2024.
4,851
For the exclusive use of C. MIB Trieste School of Management, 2024.
201-113
Exhibit 4
Apache's Revenues and Costs by Country for 2000 ($ thousands)
United States
Income Statement Information
Oil and Gas Production Revenues
Operating Expenses:
Depreciation, depletion and amortization
Operating costs
Operating Income (Loss)
Canada
Egypt
Australia
Other Int'l
1,374,941
331,503
360,772
223,543
--
2,290,759
356,998
216,001
801,942
79,892
39,559
212,052
84,425
28,328
248,019
62,183
30,536
130,824
48
-(48)
583,546
314,424
1,392,789
Other Income (Expense):
Equity in income of affiliates
Other revenues
Administrative, selling and other
Financing costs, net
Income Before Income Taxes
Balance Sheet Information
Total Long-Lived Assets
Total Assets
Additions to Long-Lived
Assets
Total
862
(7,717)
(75,615)
(106,638)
1,203,681
3,643,439
4,022,749
1,378,639
1,463,306
854,531
965,733
783,884
856,575
151,969
173,587
6,812,462
7,481,950
1,461,479
649,804
93,083
117,248
20,865
2,342,479
Source: Apache 2000 10-K
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201-113
Exhibit 5
Risk Management at Apache
Apache's Gross Wells Drilled: 1998-2000
Exploratory
Productive
Dry
Total
Developmental
Productive
Dry
Total
2000
United States
Canada
Australia
Egypt
Other International
Total
5.8
1.0
5.0
1.4
-13.2
9.1
7.0
5.8
13.7
0.9
36.5
14.9
8.0
10.8
15.1
0.9
49.7
201.0
58.7
9.7
4.3
-273.7
41.6
11.7
1.6
--54.9
242.6
70.4
11.3
4.3
-328.6
1999
United States
Canada
Australia
Egypt
Other International
Total
4.1
1.3
2.0
1.6
-9.0
8.2
2.3
5.4
1.2
1.6
18.7
12.3
3.6
7.4
2.8
1.6
27.7
59.1
26.2
2.6
15.6
0.5
104.0
4.8
12.1
0.2
1.2
-18.3
63.9
38.3
2.8
16.8
0.5
122.3
1998
United States
Canada
Australia
Egypt
Other International
Total
9.9
16.2
3.5
5.6
-35.2
11.1
11.0
3.4
13.5
0.2
39.2
21.0
27.2
6.9
19.1
0.2
74.4
64.0
28.3
-11.9
0.2
104.4
18.8
6.1
-2.8
-27.7
82.8
34.4
-14.7
0.2
132.1
Source: Apache 2000 10-K
14
This document is authorized for use only by CONSORZIO MIB Trieste School of Management in 2024.
For the exclusive use of C. MIB Trieste School of Management, 2024.
201-113
Oil Futures Prices, Apache’s Issuances of Debt and Equity, and Apache’s Property Acquisition’s
West Texas Intermediate Futures Prices
Public Issue of Debt or Equity
Bank Debt
Property acquisitions of >$200 mil. and <$400 mil.
Property acquisitions of >$400 mil.
Source: West Texas Intermediate futures prices from Datastream. Debt, equity, and acquisitions information from Thompson Financial.
This document is authorized for use only by CONSORZIO MIB Trieste School of Management in 2024.
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Phillips Petro. $490 M
C & W $321 M
$468 M
F.C.E. $630 M
Oxy Petro $365 M
$269 M
Shell Canada $519 M
1 Standard deviation below mean
$99 M
Shell Oil $743 M
$620 M
$149 M
$100 M
$148 M
Ampolex Ltd. $390 M
$148 M
$168 M
$162 M
$149 M
$417 M
Phoenix Res. $428 M
$99 M
$180 M
$203 M
DeKalb Energy $240 M
$126 M
$100 M
$195 M
10
$295 M
20
1 Standard deviation above mean
MW Petro. $540 M
30
$60 M
$ per barrel
40
Occidental Petro. $222 M
$122 M
$90 M
50
$150 M
Oil Futures Prices, Apache's Issuances of Debt and Equity,
and Apache's Property Acquisitions
$81 M
Exhibit 6
-15-
For the exclusive use of C. MIB Trieste School of Management, 2024.
201-113
Exhibit 7
Stock Performance of Apache Relative to Major and Secondary Oil Companies Indices and Oil Futures Prices
Stock Performance of Apache Relative to Major
and Secondary Oil Company Indices and Oil
Futures Prices
6
Scaled Price
5
4
3
2
1
Dow Jones Major Oil Companies
Dow Jones Secondary Oil Companies
Apache Stock
West Texas Intermediate Oil Futures Price
Source: Price data from Datastream
This document is authorized for use only by CONSORZIO MIB Trieste School of Management in 2024.
01
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-16-
For the exclusive use of C. MIB Trieste School of Management, 2024.
201-113
Exhibit 8
Firm Characteristics of Apache and Other Oil Companies
R-squared
from Market
Model
Annual
Company
Independents
Anadarko Petroleum
Apache
Barrett Resources
Burlington Resources
EOG Resources
Louis Dreyfus
Occidental
Ocean Energy
Pioneer Natural Resources
Union Pacific Resourcesa
Vastar Resourcesa
Majors
Chevron
Exxon Mobil
Texaco
b
Beta
Volatility
c
Regression
d
Sales
(MM$)
Cash
(MM$)
Market
Value
Equity
(MM$)
Long-Term
Debt
(MM$)
10.2%
6.0%
4.4%
6.7%
4.5%
10.1%
5.8%
6.9%
5.3%
5.0%
4.7%
5,686
2,291
376
3,147
1,482
490
13,574
1,074
853
1,728
1,895
199
37
25
132
20
3
97
23
26
124
41
17,782
8,662
1,897
10,886
6,386
2,002
8,972
2,907
1,938
3,158
5,761
3,984
2,218
359
2,301
859
607
5,445
1,033
1,579
2,800
975
18%
20%
18%
17%
12%
23%
38%
26%
45%
47%
14%
BBB+
ABB+
ABBB+
BBB
BBBBB+
BB+
BBBBBB+
0.51
0.32
0.19
27%
26%
31%
14.6%
10.4%
1.8%
46,532
206,083
50,100
2,630
7,081
253
54,130
301,238
33,607
6,232
13,441
7,191
10%
4%
18%
AA
AAA
A+
Correlation between oil and gas price changes
0.20
Source: CRSP, Bloomberg, Thompson Financial, Datastream
a
Year-end 2000 except Vastar Resources, Union Pacific Resources which are year-end 1999.
b
Beta calculated using 5 years of monthly returns from 1996-2000.
Annual volatility and correlation using daily returns from January-December 2000.
R-squared from regression equation with firm return as dependent variable, market return as independent variable.
e
Long-term debt as a percent of firm value, where firm value is book debt + market equity.
f
Ratingf
52%
52%
50%
46%
49%
51%
39%
62%
48%
60%
30%
57%
56%
d
% Debt
0.82
0.65
0.67
0.60
0.56
1.05
0.49
0.92
0.83
0.79
0.50
Annual Oil Price Volatility in 2000
Annual Gas Price Volatility in 2000
c
S&P Debt
e
As of January, 2001.
This document is authorized for use only by CONSORZIO MIB Trieste School of Management in 2024.
-17-
For the exclusive use of C. MIB Trieste School of Management, 2024.
201-113
Exhibit 9
Historical Volatility of Oil and Gas Futures Price Changes and Apache Stock Price Changes
Historical Volatility of Oil and Gas Futures Price
Changes and Apache Stock Price Changes
140%
120%
100%
80%
60%
40%
20%
Ja
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-9
Se 7
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Ja 7
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Se 8
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Ja 8
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Se 9
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p00
0%
Gas price volatility
Oil price volatility
Apache volatility
Source: Oil and gas future prices from NYMEX. Apache stock price data from Datastream.
This document is authorized for use only by CONSORZIO MIB Trieste School of Management in 2024.
-18-
For the exclusive use of C. MIB Trieste School of Management, 2024.
Risk Management at Apache
Exhibit 10
201-113
Sensitivity of the Firm's Stock Returns to Changes in Oil and Gas Futures Prices:
Regression I: Firm Return = α + β 1(% change in oil price) + β 2(% change in gas price)
Panel A: Independent Oil Firms
Regression Coefficients (t-statistics in parentheses)
Name of Firm
Intercept
α)
(α
% Change in Oil
Price Sensitivity
β 1)
(β
% Change in Gas
Price Sensitivity
β 2)
(β
Adjusted R2
from
Regression I
Anadarko Petroleum
0.01
(0.62)
0.42
(3.22)
0.32
(4.36)
38.7%
Apache
0.01
(0.47)
0.24
(1.81)
0.42
(5.58)
40.7%
Barrett Resources
0.01
(0.33)
0.19
(1.09)
0.46
(4.69)
30.5%
Belco Oil & Gas Corp.
-0.01
(-0.52)
0.12
(0.57)
0.27
(2.28)
7.8%
Burlington Resources
0.00
(-0.33)
0.10
(0.87)
0.40
(6.30)
41.0%
Devon Energy Corp.
0.01
(0.42)
0.15
(1.19)
0.43
(6.10)
42.9%
EOG Resources
0.00
(0.34)
0.09
(0.62)
0.44
(5.52)
36.0%
Louis Dreyfus
0.01
(0.79)
0.09
(0.49)
0.50
(4.88)
30.0%
Magnum Hunter Resources
0.02
(1.10)
-0.08
(-0.37)
0.41
(3.37)
14.2%
Newfield Exploration Co.
0.01
(0.77)
0.52
(3.87)
0.37
(4.86)
45.7%
0.00
(-0.06)
0.37
(2.44)
0.36
(4.08)
31.9%
0.00
(0.19)
0.06
(0.51)
0.20
(2.75)
10.9%
-0.01
(-0.78)
0.50
(3.02)
0.53
(5.56)
46.0%
0.01
(0.60)
0.57
(3.31)
0.49
(4.96)
46.0%
Pioneer Natural Resources
-0.01
(-0.59)
0.38
(2.07)
0.52
(4.93)
36.8%
Range Resources Corp.
-0.01
(-0.46)
0.86
(3.08)
0.62
(3.88)
34.3%
Noble Affiliates Inc.
Occidental
Ocean Energy
Patina Oil & Gas Corp.
19
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201-113
Risk Management at Apache
Exhibit 10 (continued)
Panel A: Independent Oil Firms (continued)
Regression Coefficients (t-statistics in parentheses)
Intercept
α)
(α
Name of Firm
St. Mary Land & Exploration Co.
% Change in Oil
Price Sensitivity
β 1)
(β
% Change in Gas
Price Sensitivity
β 2)
(β
2
Adjusted R
from
Regression I
0.02
(1.04)
0.28
(1.71)
0.45
(4.71)
33.2%
0.00
(-0.12)
0.25
(1.10)
0.41
(2.88)
18.1%
Unocal Corp.
0.00
(-0.1)
0.22
(2.23)
0.22
(3.95)
29.7%
Vastar Resources
0.02
(1.35)
0.06
(0.45)
0.27
(2.93)
15.4%
Vintage Petroleum Inc.
0.00
(0.17)
0.89
(4.04)
0.45
(3.56)
38.6%
Union Pacific Resources
Panel B: Major Oil Firms
Chevron
0.01
(0.94)
0.08
(1.01)
0.12
(2.54)
11.1%
Exxon Mobil
0.01
(2.18)
0.06
(0.92)
0.05
(1.35)
2.5%
Texaco
0.01
(0.71)
0.16
(1.78)
0.12
(2.36)
14.1%
Panel C: Firms outside the oil and gas industry
Bethlehem Steel Corp
-0.02
(-1.2)
-0.01
(-0.03)
-0.13
(-1.21)
0.0%
Borg Warner Inc
0.01
(0.89)
-0.08
(-0.57)
0.01
(0.13)
0.0%
Ford
0.02
(2.16)
-0.20
(-1.65)
-0.02
(-0.36)
2.2%
General Electric
0.03
(2.56)
0.04
(0.45)
0.01
(0.21)
0.0%
Goodyear Tire
-0.01
(-0.65)
-0.09
(0.67)
0.15
(1.90)
2.8%
Pepsi Co.
0.01
(1.17)
-0.14
(-1.29)
0.10
(1.57)
2.3%
Wal-Mart
0.04
(3.14)
-0.24
(-2.03)
0.03
(-0.44)
5.0%
Source: Datastream, Center for Research in Security Prices, NYMEX. Regressions employ monthly observations during the
1996-2000 period.
*During 1996-2000, the correlation between the percentage change in oil prices and the percentage change in gas prices
was 0.20. The annual volatility of oil price changes was 57%, and the annual volatility of gas price changes was 56%.
20
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Risk Management at Apache
201-113
Exhibit 11 Sensitivity of the Firm's Stock Returns to Changes in Oil and Gas Futures Prices and
Market Movements:
Regression II: Firm Return = α + β 1(% change in oil price) + β 2(% change in gas price) + β 3(market return)
Panel A: Independent Oil Firms
Regression Coefficients (t-statistics in parenthesis)
Name of Firm
Intercept
α)
(α
% Change in Oil
Price Sensitivity
(β
β 1)
% Change in Gas
Price Sensitivity
(β
β 2)
Market
Sensitivity
(β
β 3)
Adjusted R2
from
Regression II
Anadarko Petroleum
0.00
(-0.13)
0.37
(3.03)
0.33
(4.70)
0.72
(2.90)
45.9%
Apache
0.00
(-0.13)
0.20
(1.57)
0.43
(5.83)
0.59
(2.29)
44.9%
Barrett Resources
0.00
(-0.16)
0.15
(0.87)
0.47
(4.83)
0.63
(1.85)
33.3%
Belco Oil & Gas Corp.
-0.02
(-1.16)
0.05
(0.28)
0.28
(2.44)
0.96
(2.44)
15.5%
Burlington Resources
-0.01
(-1.01)
0.06
(0.58)
0.40
(6.38)
0.58
(2.57)
46.4%
Devon Energy Corp.
0.00
(-0.32)
0.10
(0.88)
0.44
(6.51)
0.66
(2.76)
49.1%
EOG Resources
0.00
(-0.17)
0.05
(0.38)
0.44
(5.69)
0.54
(1.94)
39.0%
Louis Dreyfus
0.00
(0.01)
0.02
(0.13)
0.50
(5.23)
1.05
(3.13)
39.5%
Magnum Hunter Resources
0.01
(0.54)
-0.14
(-0.65)
0.42
(3.52)
0.89
(2.11)
19.2%
Newfield Exploration Co.
0.00
(-0.12)
0.46
(3.77)
0.38
(5.42)
0.89
(3.59)
55.2%
Noble Affiliates Inc.
-0.01
(-0.68)
0.33
(2.21)
0.36
(4.29)
0.70
(2.36)
37.1%
Occidental
0.00
(-0.31)
0.03
(0.27)
0.20
(2.86)
0.47
(1.92)
14.9%
Ocean Energy
-0.02
(-1.44)
0.45
(2.81)
0.53
(5.86)
0.80
(2.48)
50.5%
Patina Oil & Gas Corp.
0.00
(-0.08)
0.51
(3.11)
0.50
(5.35)
0.91
(2.81)
52.4%
-0.02
(-1.1)
0.34
(1.85)
0.53
(5.10)
0.72
(1.97)
39.9%
34.6%
Pioneer Natural Resources
Range Resources Corp.
-0.02
0.82
0.62
0.62
(-0.73)
(2.92)
(3.91)
(1.10)
21
This document is authorized for use only by CONSORZIO MIB Trieste School of Management in 2024.
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201-113
Risk Management at Apache
Exhibit 11 (continued)
Panel A: Independent Oil Firms (continued)
Regression Coefficients (t-statistics in parentheses)
Name of Firm
St. Mary Land & Exploration Co.
Intercept
α)
(α
% Change in Oil
Price Sensitivity
β 1)
(β
% Change in Gas
Price Sensitivity
β 2)
(β
Market
Sensitivity
β 3)
(β
2
Adjusted R
from
Regression II
0.00
(0.30)
0.22
(1.43)
0.45
(5.09)
0.94
(2.95)
41.3%
Union Pacific Resources
-0.01
(-0.62)
0.24
(1.07)
0.39
(2.81)
0.66
(1.49)
20.1%
Unocal Corp.
-0.01
(-0.57)
0.20
(2.02)
0.23
(4.07)
0.36
(1.80)
32.4%
Vastar Resources
0.01
(0.83)
0.05
(0.36)
0.26
(2.82)
0.39
(1.36)
16.7%
Vintage Petroleum Inc.
-0.01
(-0.7)
0.80
(3.93)
0.46
(3.94)
1.37
(3.33)
47.9%
Chevron
0.00
(0.14)
0.05
(0.67)
0.12
(2.81)
0.49
(3.22)
23.8%
Exxon Mobil
0.01
(1.55)
0.04
(0.64)
0.05
(1.47)
0.32
(2.52)
11.0%
Texaco
0.00
(0.47)
0.15
(1.66)
0.12
(2.37)
0.15
(0.83)
13.6%
Panel B: Major Oil Firms
Panel C: Firms outside the oil and gas industry
Bethlehem Steel Corp
-0.04
(-2.36)
-0.09
(-0.55)
0.12
(-1.27)
1.33
(4.03)
20.8%
Borg Warner Inc
0.00
(0.00)
-0.13
(-1.08)
0.02
(0.22)
0.88
(3.59)
15.1%
Ford
0.01
(1.34)
-0.24
(-2.25)
-0.01
(-0.24)
0.85
(4.06)
23.7%
General Electric
0.01
(1.52)
-0.02
(-0.34)
0.02
(0.46)
1.09
(7.65)
49.2%
Goodyear Tire
-0.02
(-1.4)
-0.14
(-1.06)
0.16
(2.08)
0.76
(2.83)
13.6%
Pepsi Co.
0.00
(0.01)
-0.20
(-2.21)
0.10
(2.02)
0.95
(5.18)
33.1%
Wal-Mart
0.03
(2.39)
-0.29
(-2.39)
0.02
(0.41)
0.79
(3.65)
22.2%
Source: Datastream, Center for Research in Security Prices, NYMEX. Regressions employ monthly observations during the
1996-2000 period.
*During 1996-2000, the correlation between the percentage change in oil prices and the percentage change in gas prices
was 0.25. The annual volatility of oil price changes was 57%, and the annual volatility of gas price changes was 56%.
22
This document is authorized for use only by CONSORZIO MIB Trieste School of Management in 2024.
For the exclusive use of C. MIB Trieste School of Management, 2024.
201-113
Exhibit 12
Oil and Gas Producers' Hedges in Place for Years 2000 and 2001
Panel A: Year 2000 Hedges
Crude & Natural Gas Liquids
Average
Percent of
Hedged Price
Production
per BBL
Natural Gas
Average
Percent of Hedged Price
Production
per MCF
Total Production: Oil & Gas
Percent of
Average
Total Effect on
Total
Hedged Price Cash Flow per
Production
per BOE
Share (%/share)
Anadarko Petroleum Corp.
0%
-
0%
-
0%
n/a
0%
Apache Corp.
17%
$21.75
7%
$3.35
12%
$21.24
-3%
Barrett Resources Corp.
0%
-
48%
$2.95
45%
$17.69
-18%
Belco Oil & Gas Corp.
91%
$19.40
65%
$2.60
75%
$17.33
-32%
Burlington Resources Inc.
18%
$20.50
34%
$2.50
31%
$15.62
-14%
Devon Energy Corp.
0%
-
12%
$1.96
8%
$11.74
-3%
EOG Resources, Inc.
8%
$20.00
0%
-
1%
$20.00
-1%
Magnum Hunter Resources
62%
$24.44
12%
$2.45
26%
$21.08
-17%
Newfield Exploration Co.
50%
$22.02
39%
$3.00
42%
$19.23
-14%
Noble Affiliates, Inc.
16%
$21.73
0%
-
5%
$21.73
-2%
Ocean Energy, Inc.
64%
$21.19
25%
$2.85
44%
$19.98
-16%
Patina Oil & Gas Corp.
78%
$21.88
60%
$2.72
64%
$17.87
-26%
Range Resources Corp.
50%
$23.65
69%
$2.69
64%
$17.65
-27%
Santa Fe Snyder Corp.
46%
$21.97
6%
$3.30
26%
$21.70
-7%
St. Mary Land & Exploration Co.
54%
$21.91
39%
$2.43
43%
$16.98
-16%
Union Pacific Resources Group
61%
$21.09
56%
$2.66
58%
$17.91
-17%
Unocal Corp.
0%
-
0%
-
0%
n/a
0%
Vintage Petroleum, Inc.
37%
$25.28
0%
-
26%
$25.28
-5%
Average of Large Capitalization Firms
23%
18%
20%
-8%
Average of Small Capitalization Firms
71%
53%
58%
-23%
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For the exclusive use of C. MIB Trieste School of Management, 2024.
201-113
Exhibit 12 (continued)
Panel B: Year 2001 Hedges
Natural Gas
Crude & Natural Gas Liquids
Total Production: Oil & Gas
Percent of
Production
Average
Hedged Price
per BBL
Percent of
Production
Average
Hedged Price
per MCF
Percent of
Total Effect on
Average
Total
Hedged Price Cash Flow per
per BOE
Production
Share (%/share)
Anadarko Petroleum Corp.
0%
-
0%
-
0%
n/a
0%
Apache Corp.
7%
$18.80
0%
-
3%
$18.80
-1%
Barrett Resources Corp.
0%
-
38%
$2.93
36%
$17.60
-2%
Belco Oil & Gas Corp.
59%
$19.80
65%
$2.65
63%
$17.29
-29%
Burlington Resources Inc.
16%
$20.50
10%
$2.40
11%
$16.16
-6%
Devon Energy Corp.
0%
-
5%
$1.84
3%
$11.04
-2%
EOG Resources, Inc.
0%
-
0%
-
0%
n/a
0%
Magnum Hunter Resources
0%
-
0%
n/a
0%
n/a
0%
Newfield Exploration Co.
19%
$21.65
16%
$2.98
17%
$18.97
-5%
Noble Affiliates, Inc.
0%
-
0%
-
0%
n/a
0%
Ocean Energy, Inc.
8%
$17.00
0%
-
4%
$17.00
-2%
Patina Oil & Gas Corp.
34%
$23.68
11%
$3.37
16%
$21.81
-5%
Range Resources Corp.
0%
-
6%
$3.03
5%
$18.18
-3%
Santa Fe Snyder Corp.
16%
$16.87
0%
-
8%
$16.87
-4%
St. Mary Land & Exploration Co.
15%
$21.26
29%
$3.03
25%
$18.65
-7%
Union Pacific Resources Group
30%
$25.25
1%
$2.40
11%
$24.85
0%
Unocal Corp.
0%
-
0%
-
0%
n/a
0%
Vintage Petroleum, Inc.
0%
-
0%
-
0%
n/a
0%
Average of Large Capitalization Firms
8%
4%
5%
-2%
Average of Small Capitalization Firms
28%
25%
26%
-9%
Source: Deutsche Bank Alex. Brown Analyst Report July 14, 2000
This document is authorized for use only by CONSORZIO MIB Trieste School of Management in 2024.
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