, , , , , , ,

GAO found that between 1991 and 2000 there were over 2,600 mergers, acquisitions, and joint ventures in the U.S. petroleum industry.

It is also true that the number of operating refineries in the United States has declined to 149 from a peak of 324 in 1981. No significant new refineries have been constructed in the United States for a quarter of a century.

(From -)



Concentration in Domestic Petroleum Refining and Marketing
One of the most important features of the domestic petroleum industry has been the significant level of consolidation at the refining and marketing level over the last 20 years. The FTC reports 1,165 mergers in the domestic petroleum industry between 1985 and 2003, at an estimated total value (for transactions of $10 million or more) of about $500 billion dollars.3 The Government Accountability Office (GAO), however, cites a much higher figure over a shorter period of time–2,600 transactions from 1991 to 2000.4

A number of features of recent petroleum merger activity stand out. First, this activity has shadowed the wave-like, economy-wide pattern in consolidation over the last two decades. Second, the average size of a petroleum merger was three times larger than the
average merger deal. Moreover, billion-dollar mergers accounted for about 86 percent of the total $500 billion in larger transactions.

Third, merger transactions have been disproportionately allocated over various segments of the industry. For example, GAO estimates that 85 percent of mergers proposed during the 1990s were in upstream exploration and production.


Two percent of mergers occurred in midstream pipeline transportation and 13 percent of transactions involved downstream refining and markets.5 Despite the intensity of merger activity in the upstream segment of the industry, about two-thirds of billion-dollar petroleum mergers in the U.S. involved downstream, integrated assets. Data on mergers enforced by the FTC confirm this observation. For example, of the 72 relevant markets defined by the agency in 15 petroleum merger enforcement actions in the 1980s and 1990s, 36 percent were related to refining and 33 percent involved marketing.6 Several transactions (beginning in the mid 1990s) were sizable combinations involving integrated “majors” such as BP-Amoco and Exxon-Mobil and the unintegrated “independents” such as Ultramar Diamond Shamrock- Total.

Third, consolidation in refining and marketing generated a relatively higher level of antitrust scrutiny. On average, about 13 percent of petroleum and marketing transactions that were cleared for investigation by either FTC or DOJ were challenged, as compared
to roughly two percent of all transactions. These challenges include transactions in which one of the agencies filed a complaint, requested injunctive relief, or settled the case through consent decree.


In the majority of merger enforcement actions in downstream petroleum, the FTC has posited horizontal theories of harm in which the merged firm could unilaterally withhold capacity to drive up price or achieve the same result through coordinated interaction. It is not clear, however, if vertical theories of harm have played a substantive role in petroleum merger analysis. These include, for example, the foreclosure of rival gasoline retailers by vertically integrated refiner-marketers in order to increase profits in retail markets. Enforcement statistics for all industries indicate that in only about nine percent of merger cases did the agencies propose a vertical theory of harm.7


3 Federal Trade Commission (August 2004). The Petroleum Industry: Mergers, Structural Change, and
Antitrust Enforcement, Tables 4-6 and 4-11.
4 Government Accountability Office (July 15, 2004). Mergers and Other Factors That Affect the U.S.
Refining Industry, p. 0.
5 Jim Wells (September 21, 2005). Factors Contributing to Higher Gasoline Prices, Testimony of the
Director, Natural Resources and Environment, Government Accountability Office, p. 2.
6 Data are for the 1980s and 1990s Enforcement actions are those cases in which the FTC required
divestiture or other remedial conditions to address competitive concerns. See Federal Trade Commission
(undated). “FTC Enforcement Actions in the Petroleum Industry, 1981-2002.”

7 FTC, Horizontal Merger Investigation Data, Fiscal Years 1996-2005, Table 1.
8 See http://tonto.eia.doe.gov/dnav/pet/hist/mocggu2A.htm.




Schlumberger to Buy Smith for About $11.3 Billion (Update2)

February 21, 2010, 03:17 PM EST

Feb. 21 (Bloomberg) — Schlumberger Ltd., the world’s largest oilfield services company, will buy Smith International Inc. for about $11.3 billion in an all-stock transaction, gaining sole ownership of the biggest drilling-fluids provider.

( . . . )

Including its M-I Swaco joint venture with Schlumberger, Houston-based Smith is the world’s largest provider of oil and natural-gas drilling fluids. Smith is the second-biggest provider of drill bits, a “critical link” for Schlumberger in offering a full range of drilling products and services, RBC Capital Markets said Feb. 19 in a note to clients.


Schlumberger, based in Houston and Paris, said it expects to see pretax savings of $160 million next year and $320 million in 2012, with the transaction adding to earnings in 2012. Schlumberger had sales of $22.7 billion last year, a 16 percent drop from 2008.

Smith had net debt of $1.2 billion as of the end of 2009, it said in a Jan. 27 statement.

The transaction is the biggest U.S. merger for this year and is Schlumberger’s biggest acquisition, according to Bloomberg data. It’s also the biggest acquisition of an oilfield-services company since Bloomberg began tracking merger statistics more than a decade ago.

( . . . )

Schlumberger is getting advice on the transaction from Goldman Sachs Group Inc. and Baker Botts LLP. Smith is using UBS AG and Wachtell Lipton Rosen & Katz.

At the same time, Schlumberger benefits by gaining sole ownership over the M-I Swaco venture it shares with Smith, Weiss said. Smith has a 60 percent interest in the joint venture, which generated $4.22 billion of Smith’s $8.22 billion in revenue in 2009.

Antitrust Concerns

A takeover of Smith could prompt antitrust regulators to force asset sales to prevent Schlumberger from having too much market share in certain categories, said Weiss, the Argus Research analyst. Areas of overlap between the companies include directional drilling and logging of well results, according to a note to clients Feb. 19 by Houston investment bank Tudor, Pickering, Holt & Co.


By David Wethe and Edward Klump

–With assistance from Zachary Mider in New York, Stanley Reed and Eduard Gismatullin in London and Marianne Stigset in Oslo.

–Editors: Susan Warren, Joe Sabo.


These price increases represent a money transfer from consumers of oil and

petroleum products to the U.S. oil industry and foreign oil producers. For example,

U.S. consumers used, on average, about 9 million barrels per day of gasoline in 2004.

With the average price of gasoline for the year about $0.28 per gallon higher than in

2003, American consumers spent an additional $105 million per day for gasoline

compared to 2003. This money became increased revenues for the oil industry. In

a functioning market economy, increases in revenue are likely to lead to investment

in the industry, expansion of supply, and ultimately moderating prices for consumers

in the longer term. If this self-correcting process is not working, this could be an

indication that factors other than traditional profit and investment incentives are at

work. These would likely result in additional long term increases in price and profit

for the industry. The public has an obvious interest in determining whether the

market process is working effectively to expand supply in the oil industry.

In 2004, the net incomes of the nine integrated oil companies rose by 39%

compared to a similar period in 2003, while revenues rose by 26%.2


1Energy Information Administration, Weekly Petroleum Status Report, for the week ending

July 22, 2005, Table 14, p.27. Gasoline price data does not include taxes.

2Oil Daily, Profit Profile, November 15, 2004, p.7.


Profits in the oil industry have been volatile over the past three decades,

reflecting oil price changes as well as other market effects. For example, net income

for the major energy companies, as defined by the Energy Information

Administration (EIA), increased almost threefold by 1981, compared to 1977, on the

oil price increases associated with the Iran-Iraq war. By 1986, net incomes of the

major energy companies had sunk below 1977 levels. Profits peaked and declined

at least three other times during the period 1987-2002.5 Volatility in the price of oil,

which leads to volatility in profits, makes investment planning risky. Investments

which might qualify for implementation if a high oil price is assumed may not qualify

if a lower price of oil is assumed. This uncertainty may have contributed to the

cyclical nature of investment and capacity expansion in the industry.

5Historical net income data for the major energy companies is available at the EIA website,

http://www.eia.doe.gov/pub/energy.overview/frs/s5110.xls (as viewed on July 19, 2005).

Net income totals are not adjusted for inflation.

6West Texas Intermediate is the benchmark crude oil which is the basis for futures trading

on the New York Mercantile Exchange. Cushing, Oklahoma, is the delivery point for New

York Mercantile Exchange traded crude oil.

Table 2. Financial Performance of the Major Integrated Oil

Companies, 2002-2004

(million of dollars)


Net Income Revenues

Company        2002 2003 2004 2002 2003 2004

Exxon Mobil $11,220 $21,654 $25,330 $178,909 $213,199 $298,027

BP 6,922 10,437 16,208 178,721 232,571 294,849

Royal Dutch/Shell 9,577 12,606 18,536 179,431 201,728 265,190

Chevron Texaco 1,189 7,506 13,328 91,685 112,937 155,300

Conoco Phillips 762 4,585 8,129 50,512 90,458 136,900

Marathon 709 1,314 1,261 27,214 36,678 49,907

Amerada Hess -218 467 977 11,932 14,311 16,733

Occidental 1,240 1,657 2,491 7,338 9,326 11,368

Murphy 97 301 701 3,966 5,275 8,359

Total $31,498 $60,527 $86,961 $729,708 $916,483 $1,236,663

Source: Oil Daily, Profits Profile Supplement, v. 55, No. 39, February 28, 2005. p. 8, and Financial

Data by Company at: www.Hoovers.com.

Company Net Income Revenues
Company 2002 2003 2004 2002 2003 2004
Exxon Mobil $11,220 $21,654 $25,330 $178,909 $213,199 $298,027
BP 6,922 10,437 16,208 178,721 232,571 294,849
Royal Dutch/Shell 9,577 12,606 18,536 179,431 201,728 265,190
Chevron Texaco 1,189 7,506 13,328 91,685 112,937 155,300
Conoco Phillips 762 4,585 8,129 50,512 90,458 136,900
Marathon 709 1,314 1,261 27,214 36,678 49,907
Amerada Hess -218 467 977 11,932 14,311 16,733
Occidental 1,240 1,657 2,491 7,338 9,326 11,368
Murphy 97 301 701 3,966 5,275 8,359
Total $31,498 $60,527 $86,961 $729,708 $916,483 $1,236,663

Aggregate net income rose in 2004 for the major integrated oil companies,

compared to 2003, which itself was a strong year for industry profit performance, and

rose by an even greater amount compared to 2002. Only ExxonMobil (17.8%)

experienced a gain of less than 20%, and only Marathon (-4.5%) experienced lower

net income in 2004 than in 2003. Five of the companies in this group posted net

income gains in excess of 50% for 2004, while the average gain in net income was

approximately 40%. Comparing 2004 to a 2002 base, the gains in net income totaled

over 175% for the major integrated oil companies.


Total revenue growth for 2004 compared to 2003 was 35% for the group, which

was less than the 44% growth in net income, suggesting that possibly the greater

profitability of the major oil companies in 2004 did not arise solely from the higher

price of crude oil. Compared to 2002, revenue growth for 2004 was approximately

70%, less than the 175% growth in net income for the same period.

The profit rate on sales for this group of oil companies, based on the totals of

revenue and net income reported in Table 2, were 7% for 2004, 6.5% for 2003, and

4.3% in 2002. The growth in the profit rate experienced by these companies

suggests that the stronger underlying market fundamentals in the crude oil and oil

product markets were successfully translated into increased performance by the



Table 5. Financial Performance of Independent Oil

Companies, 2004

(millions of dollars)

Net Income Revenues Oil Production

(000 b/d)

Gas Production

(MM cf/d)

2004 % Change 2004 % Change 2004 % Change 2004 % Change

Devon $2,176 25.3 $9,189 25.0 $279 21.3 $2,433 2.8

Unocal 1,208 87.9 8,204 26.0 159 -0.6 1,510 -14.4

Anadarko 1,601 24.4 6,067 18.4 230 -0.4 1,741 -1.2

Burlington 1,527 27.1 5,618 30.3 151 36.0 1,914 0.8

Apache 1,663 49.0 5,333 27.3 242 12.6 1,235 1.5

Kerr-McGee 404 84.5 5,179 23.8 159 5.3 921 21.2

EDG 614 46.5 2,271 30.1 33 22.2 1,036 7.8

XTO 508 76.4 1,948 63.7 30 57.9 835 20.0

Pioneer 313 -23.8 1,847 43.5 69 19.0 685 18.4

Newfield 312 56.0 1,353 33.0 21 23.5 666 9.3

Total $10,326 37.3 $47,009 27.4 $1,373 12.6 $12,976 3.8

Source: Oil Daily, Profits Profile Supplement, v. 55, no. 39, February 28, 2005. p. 8.

Table 6. Financial Performance of Independent Refiners

and Marketers, 2005

(millions of dollars)

Net Income Revenues Product Sales

(000 b/d)

2004 %Change 2004 %Change 2004 %Change

Valero $1,791 187.9 $54,619 43.9 N.A. N.A.

Sunoco 605 93.9 25,508 41.6 903 19.8

Premcor 478 308.5 15,335 74.2 N.A. N.A.

Tesoro 328 331.6 12,262 38.6 604 8.4

Ashland 101 197.1 2,177 12.4 1,414 4.4

Frontier 70 2,233.3 2,862 31.8 166 0.0

Total $3,737 189.8 $112.763 45.0 $3,087 9.0

Source: Oil Daily, Profits Profile Supplement, v. 55, no. 39, February 28, 2005. p. 8.

N.A. = Not available.

As shown in Table 6, these firms did expand their product sales in response to

the high prices of 2004. The 9% expansion in product sales by these firms in 2004

was about six times the magnitude of the increase in production generated by the

major integrated oil companies in their comparable downstream business, although

the independent’s production base was smaller.9 The 9% increase in product sales

translated into a 45% increase in revenues which resulted in a 190% increase in net

income, with every company in the reporting category, except one, achieving at least

triple digit increases. This performance, coupled with the downstream profitability

of the major integrated oil companies, gives some support to the viewpoint that, in

addition to high oil prices, conditions in the petroleum product markets, especially

gasoline, decoupled from their traditional linkage to crude oil and generated

independent market tightness and higher prices.

Key profit indicators in the refining industry are the gross and net refining

margins.10 Table 7 presents data for the twenty four firms included in the EIA’s set

of major energy companies.11

9Not all the increase in product sales was necessarily due to expanding production. Over

the past decade, the oil industry has experienced asset churning. The major oil companies

have sold producing fields, refineries, and other assets as a result of merger and acquisition

requirements, inadequate returns from smaller fields and refineries, or changes in business

focus to a more international stance. These assets have typically been acquired by the

independent oil and gas producers and the independent refiners and marketers. These asset

transfers might bias the major integrated oil companies’ production totals downward, while

the independents’ production totals rise. The net effect might just be a reallocation of

existing productive capacity.

Table 7. Refining Margins, 1990 – 2004

(dollars per barrel)

1995 1997 1998 1999 2000 2001 2002 2003 2004
Gross Refining Margin 7.20 4.40 6.53 5.82 7.34 7.94 6.36 10.70 13.82
Net Refining Margin 0.97 1.61 1.63 1.17 2.32 2.76 0.19 2.06 __

Source: Energy Information Administration, Performance Profiles of Major Energy Producers 2003, Table B-32, p. 101, and Financial News for Major Energy Companies, updated March 9, 2005, Table 2.

(From -)



For the years 1996 through 2002, the net refining margin averaged $1.44 per

barrel of refinery throughput. The value of the gross refining margin in 2003 was

approximately 7 times the average for the previous seven years.

The gross margin increased by a further 29% in 2004 compared to 2003. With domestic refinery throughput approximately 13.5 million barrels per day, and the gross refining margin approaching $14 per barrel, the source of the profit performance of the oil companies’ downstream operations and the independent refiners and marketers is clear.

10The gross profit margin is defined as the revenue achieved from petroleum product sales

minus the cost of crude oil, the primary input. When a further deduction in operating costs

is made, the result is the net margin. These margins are usually expressed on a per barrel


11The EIA publishes aggregated financial data for both major and independent energy

producers. Company specific data on refining profitability is proprietary. The firms

included in Table 7 are: Amerada Hess Corporation, Andarko Petroleum Corporation,

Apache Corporation, BP (only U.S. operations), Burlington Resources, Inc., Chesapeake

Energy Corporation, ChevronTexaco Corporation, CITGO Petroleum Corporation,

ConocoPhillips Inc., Devon Energy Corporation, Dominion Resources, Inc., EOG

Resources, Inc., Equitable Resources, Inc., ExxonMobil Corporation, Kerr McGee

Corporation, Lyondell Chemical Company, Marathon Oil Corporation, Occidental

Petroleum Corporation, Premcor, Inc., Royal Dutch Shell Group(only U.S. operations),

Sunoco, Inc., Tesoro Petroleum Corporation, Unocal Corporation, Valero Energy

Corporation, Williams Companies, Inc., XTO Energy, Inc.


The gross refining margins of 2003 and 2004, which increased by a greater

percentage than the price of crude oil, are a likely indication that tightness in the

gasoline market, which is linked to a refining sector running at nearly full capacity,

has led to profits that increased by a larger percentage than the price of crude oil.

Another indication of tightness in the refining sector is that imports of finished

gasoline, as well as gasoline blending components, have been increasing and were

at record levels in 2004. It is also true that the number of operating refineries in the

United States has declined to 149 from a peak of 324 in 1981. No significant new

refineries have been constructed in the United States for a quarter of a century. The

refining capacity growth that has occurred in the United States since 1990 has been

largely due to improvements made at existing facilities, called capacity creep.


Mergers and Acquisitions

The oil industry of today has evolved to its current structure partly through years

of mergers, acquisitions, and joint ventures. In May 2004, the Government

Accountability Office (GAO) released a study on the effects of mergers and the

restructuring of the U.S. petroleum industry.17 GAO found that between 1991 and

2000 there were over 2,600 mergers, acquisitions, and joint ventures in the U.S.

petroleum industry. A majority of the transactions took place in the last five years

of the decade. The transactions took place at all stages in the chain of production,

from exploration and production, through refining and marketing. These transactions

included deals among the very largest oil companies. For example, in 1999 Exxon

Corporation acquired Mobil Oil; in 1998 British Petroleum and Amoco formed BPAmoco,

which acquired ARCO in 2000; and in 2001 ChevronTexaco was formed.


Merger activity is again on the rise in the U.S. petroleum industry. In April

2005, ChevronTexaco made a $17 billion stock and cash bid to acquire Unocal, the

number 9 oil company in the United States, ranked by reserves of crude oil. Unocal

was also targeted for takeover by CNOOC Ltd., a company majority-owned by the

Chinese government, in a bid that has since been withdrawn.18 In the same month,

Valero Energy Corp. bid to acquire Premcor Inc., to form the largest refining

company in the United States in a $6 billion deal.


As a result of the profitability of the last year, companies with large cash

reserves on their balance sheets are searching for ways to better position themselves

on the world oil market, increase their crude oil reserves and other assets, and create

economies of scale and cost savings. Individually, they are able to accomplish these

goals through mergers and acquisitions. In addition, a large amount of accumulated

profits is returned to investors, usually at a premium price, through these transactions.

Although these transactions may improve the market position of the firms

involved and imply the expenditure of billions of dollars of accumulated profit, they

do little to improve the nation’s demand and supply balance with respect to oil and

petroleum products in the near term.

17United States General Accounting Office, Energy Markets: Effects of Mergers and Market

Concentration in the U.S. Petroleum Industry, GAO-04-96, May 2004.

18Manimoli Dinesh, CNOOC Seeks Quick US Review of Unocal Bid, Oil Daily, Vol.55,

No.127, July 5, 2005. p.1.

(From same document)


Dividends and Share Purchases19

The firms that make up the oil industry are private firms that use shareholder

capital to engage in business operations. When they make profits they are obliged

to return those profits to shareholders, unless management deems it likely that

business opportunities exist such that reinvestment will yield even larger future

profits for shareholders.

The major oil companies have increased dividends for shareholders, but in

general, by less than increases in available funds. For example, ExxonMobil

increased quarterly dividends by $0.02 per share during 2004, an increase of about

8%. However, during the last quarter of 2004 earnings per share increased by $0.42,

an increase of about 47%. For the years 2002 through 2004, earning per share

increased from $1.68 to $3.89, an increase of approximately 130%, but dividends,

the amount actually paid out to shareholders, increased by only about 15%.

ExxonMobil did however reduce the number of shares outstanding over the period

by about 300 million, to 6.4 billion from 6.7 billion. If a company re-purchases its

shares, the value of shares outstanding is likely to increase and the company may

choose to re-sell them on the market if it needs capital in the future. ExxonMobil

also held over $18 billion in cash at the end of 2004, an increase of 75% over the


A similar dividend strategy was in place at ChevronTexaco, where quarterly

dividends increased by $0.03 per share during 2004, an increase of about 8%, while

earnings per share almost doubled compared to levels attained in the last quarter of

2003. For ChevronTexaco, earnings per share increased over the period 2002 to

2004 by an approximate factor of 10, from $0.54 to $6.28, while yearly dividends per

share increase from $1.40 to $1.53, an increase of about 9%. The number of

ChevronTexaco shares outstanding declined by about 29 million.

ConocoPhillips, over the period 2002 through 2004 increased yearly dividends

from $0.74 per share to $0.90 per share, an increase of about 21%. However,

earnings per share increased from a loss of $0.31 in 2002 to $5.81 in 2004.

ConocoPhillips increased the number of shares outstanding over the period by about

34 million.

Limited dividend payouts, coupled with a modest expansion of investment in

relation to profit has left oil companies highly liquid and well positioned to take

advantage of future market opportunities.


Since oil price increases began in 2004, the oil industry has earned increased

profits. These profits might have resulted from other factors in addition to the

increased price of oil. A key factor in increased profitability might be the tightness

in the U.S. gasoline market, a factor related to the lack of enough refinery capacity

to meet U.S. demand for petroleum products.

If oil and petroleum product prices are to decrease, supply will likely have to

increase relative to demand. Expanded supply results from investment in the various

stages of the oil industry production process, from exploration and development of

new oil fields to increased refinery capacity. If the underlying economic parameters

and the regulatory environment are not encouraging, investment might not be

undertaken. Historically volatile prices and profit levels coupled with a tight

regulatory environment contribute to industry uncertainty.

Other legitimate uses for earned profits include paying higher dividends and

retiring outstanding shares, acquiring assets through merger and acquisition, and

investing in new product areas. These uses of profit may benefit shareholders and

strategically position the firm in the global market, but they do less to expand the

supply of oil and products on the market and thereby reduce prices for consumers.

As a result of significant time lags that tend to occur in the oil industry, it may

be too soon to know whether or not investments in the industry, if taken, will result

in the increased supply of oil and petroleum products needed to reduce prices and

consumers’ costs.

19Financial data used in this section was obtained at http://www.hoovers.com, viewed on

June 21, 2005.


(see appendices below)



Appendix: Measuring Profit

In a market economy, a firm’s key measure of success is its ability to earn a profit. Profit is important to firms because it is a signal to the financial markets and investors that the firm is worthy of funding either through debt or equity capital.

Firms that earn less profit than expected by the market have difficulty funding investment opportunities with negative implications for growth. Firms that consistently earn less than adequate profits tend to experience slow growth, stagnation, and ultimately, failure.

Profit is seemingly a simple concept. Total cost is subtracted from total revenue, leaving a residual, total profit. In this approach, profit is measured in dollars. For the oil industry, the simple total revenue minus total cost approach is complicated by the difficulty in neatly separating the revenue-generating outputs of the firms from the cost-creating production inputs.

For any given oil company, crude oil price changes may affect both the revenues and costs of the company. If the company is an upstream producer and sells crude oil, the production of crude oil is revenue generating. However, downstream operations, notably refining and marketing, make use of crude oil as a raw material, and for them, the acquisition of crude oil is a cost. As a result, it is not always clear that an increase in the price of crude oil will raise, or lower, profits for firms with differing positions in the upstream and downstream segments of the industry.

Another key factor in the profit calculation is how easily the increase in the cost of crude oil can be passed on to consumers in the form of higher prices for gasoline and other refined products without suffering a more than proportionate decrease in sales. If cost increases can be passed on to consumers, and the firm has significant upstream business interests, then it is more likely that an increase in the price of crude oil will yield increased profits.

A simple way to rank companies, for comparative purposes, is by total profit.

However, this type of simple ranking is likely to provide a misleading picture of the

relative performance of the companies in the oil industry.

While the total dollar value of profit is important, it may be equally important

to know the value of the resources, or assets, at a firm’s disposal that were used to

earn a given dollar level of profit. The size of the firm relative to the level of total

profit is important, especially for investment analysts. For this reason, the most

commonly used measures of profit in investment analysis are expressed as

percentages, or rates, independent of specific magnitudes. The use of percentages

allows meaningful comparisons to be made between companies of different sizes and

differing access to resources.

Profit also can be measured to include or exclude special, non-recurring items

that may temporarily affect a company’s revenues and costs. For example, if a

company incurs substantial costs and legal penalties associated with an

environmental cleanup due to an oil spill at one of its facilities, its profit performance

for the relevant time period might well be negatively affected. However, profit

numbers that include the costs resulting from the spill may tell potential investors

and other interested parties little about the real, continuing, business performance of

the company.20 Profits from continuing operations, excluding one-time charges (or

revenues), may be more informative for some purposes.

All stakeholders in a company do not necessarily have an interest in the same

conceptual definition of profit. Accountants are interested in profit calculations that

meet generally accepted accounting practices and are consistent with the tax code.

Economists use profit as a signal to judge the efficiency of resource allocation

decisions and include opportunity costs in their calculations.21 Potential investors in

the company’s stocks and bonds may choose to evaluate profit from a still different

perspective, comparing profit to a measure of the assets management had available

for business purposes relative to the risk the company faced.


20A large, non-recurring expense might, however, affect a company’s financial condition.

21Opportunity costs are the value of the returns that could be earned in the next best

alternative. For example, if a firm earns $100,000 in profits according to the tax laws, but

could earn $150,000 from liquidating the firms resources and applying them to another

activity, an economist would observe that the firm lost $50,000 by engaging in its current

activities rather than having made $100,000 in profit.

22The answer to this question requires a set of profit results over time, as sales have

presumably grown. In general, it is more revealing to have a time dependent set of profit

data, rather than one data point, so that trends may be ascertained.

23Operating income is defined as gross profit minus operating expenses. It is profit before

the payment of interest and income taxes. It is considered to be a measure of how well the

firm has succeeded in making money from the sales of goods and services, before financial

and tax obligations are considered.

The Profit Rate

Even once the efficacy of using a profit rate is determined, measurement issues

still need to be addressed. Since profit as a rate, or percentage, must be expressed

relative to some base, an appropriate base must be specified. Three possible bases,

widely used in business analysis, are sales, assets, and net worth, or shareholder

equity. Each is useful in answering particular questions about the operation of the

business, but none necessarily serves as an all-purpose profit measure.

The profit margin on sales uses the total sales revenue of the business as the

base and expresses profit, or net income, as a percentage of sales revenue. Profit

rates expressed in this manner can answer questions as to whether increasing sales

become more or less profitable as the business grows.22 This profit measure can also

lead analysts to basic questions as to whether the businesses’ prices were too low or

too high, or whether adequate cost controls were in place as the business expanded.

A variation on this profit measure results from replacing net income in the

calculation with operating income.23

Profits based on assets, or the return on assets, divides profit, or net income, by

the value of the total assets of the business. This measure allows analysts to

determine how well management uses the asset base of the company to generate

profits for investors. If the asset base represents the tools available to management


24In the case where a firm has no debt, assets must equal owner’s equity and the two profit

measures will be identical.

to carry out business activities, the return on assets gives an indication of how

effective management has been in using those tools. This approach has been

criticized by some because certain “intangibles” important to the functioning of the

business may not receive adequate weight in this measure.

A profitability rate popular with potential investors is the return on equity, or the

return on net worth. This measure divides profit, or net income, by the value of

shareholders equity in the firm. Since the fundamental accounting identity, Assets=

Liabilities + Owners Equity, must always hold, for every business, this profit rate is

generally greater than, and at least equal to, the return on assets.24 This measure is

especially interesting to investors who might plan to buy shares of stock in the

business. While this profit measure may be revealing to potential investors, care

should be exercised in its use. If two businesses have the same asset value and the

same level of profits, differences in return on net worth can arise solely as a result of

the amount of debt financing on the firm’s balance sheet, a difference purely of

financial structure, unrelated to a firm’s ability to efficiently produce goods and earn

revenues from selling goods. This can generate misleading conclusions about the

strength of the firm’s performance, because the choice of financial structure for a

business is not generally related to its current profitability from continuing


Another measure, sometimes identified with profitability, is earnings per share.

This measure divides profit, or net income, by the total number of shares of common

stock outstanding. Earnings per share provides the prospective maximum of

dividends per share that might be paid by the firm. However, it is not a relevant

measure to evaluate profit. Like the return on net worth, it is affected by the capital

structure of the company, the division between equity and debt financing. Earnings

per share can also be directly affected by strategic management decisions. Firms may

decide to buy back shares of common stock and retire them, holding them as treasury

shares. This type of strategy raises earnings per share by decreasing the number of

outstanding shares over which any level of net income is divided. This strategy

might well be viewed negatively by financial analysts, who might interpret it as a

signal that the firm does not have, or recognize, profitable investment opportunities

available, and hence chooses to return to shareholders the money they had invested

in the company.

An important factor in analyzing profit data is that in many cases it is more

informative to use comparative analysis. Comparisons can be made over time, with

other companies in the same industry, or with other companies that bear the same

level of risk.

Time-based comparative profit analysis may be helpful because it suggests the

direction the company is heading, or the direction of market trends. A particular rate

of profit might be viewed as favorable if it was embedded in a trend of rising profit

rates, or unfavorable if embedded in a trend of falling profit rates. Time trends might

also help to identify correlations between profit and other factors which influence


25Risk is defined as the dispersion of the rate of return for the company. In terms of the

stock market, risk is usually measured, somewhat incompletely, to reflect the dispersion in

the movement of share prices, without accounting for variations in dividends.

profits. In addition, key lags that affect profit are also more likely to be identified in

a time trend.

Standing alone, any rate of profit might be difficult to evaluate. Comparisons

can be drawn with other firms in the same, or closely related, lines of business to

determine whether a particular firm is a profit leader, average, or a low profit earner

within its industry cohort. Barring special circumstances, which should be clearly

reported in the company’s financial statements, if two firms in the same line of

business, with approximately the same asset base, report very different profit rates,

it is possible that this differential might suggest that one or the other firm’s

management strategy is superior. Looking at profit rates of different sized firms

within the same industry allows the analyst to assess whether growth of the firm to

a larger scale may imply any advantage or disadvantage with respect to profit.

In some cases, particularly for investment decisions, the most relevant

comparison is with firms with a comparable level of risk, independent of the line of

business in which the firms are engaged.25 This approach is appropriate for

prospective investors because they may have less interest in what business activity

a firm undertakes, than the results of that activity in terms of profits earned and risk

borne. In many cases, profits can be expressed in comparison to an index of firms

designed to show average, or market, returns and risk.

25Risk is defined as the dispersion of the rate of return for the company. In terms of the

stock market, risk is usually measured, somewhat incompletely, to reflect the dispersion in

the movement of share prices, without accounting for variations in dividends.



  1. [PDF]

May 2007_JEC Testimony on Petroleum

File Format: PDF/Adobe Acrobat – Quick View
May 27, 2007 United States Senate. May 23, 2007. 10:00 am. 216 Hart Senate Office Building. “Is Market Concentration in the U.S. Petroleum Industry …. For example, GAO estimates that 85 percent of mergers proposed during …. Concentration in U.S. refining markets should carefully scrutinized against the

2.     Public Citizen | Energy Program | Energy Program – U.S. Senate … onmouseover=”pocpop(“1d5khj5″,event,6)” border=0>

Congress can restore accountability to oil and gas markets and protect consumers by …. [9] Net Imports of Crude Oil and Petroleum Products in the United States by Country, 2004, [10] Effects of Mergers and Market Concentration in the U.S. Petroleum Industry, GAO-04-96, www.gao.gov/new.items/d0496.pdf
http://www.publiccitizen.org/cmep/energy…/Oil_and_Gas/articles.cfm?… – Cached

3.     API Statement to Senate Judiciary on the State of the Oil … onmouseover=”pocpop(“1d5khj5″,event,7)”>

Sep 21, 2006 The most recent forecasts of the United States Department of Energy’s Energy concentration for most levels of the petroleum industry has remained low to moderate. They found that “increased market concentration generally led to higher whole …. GAO Silent on Retail Price Effects of Mergers

  1. [PDF]

Market Structure and Price Adjustment in the U.S. wholesale …

File Format: PDF/Adobe Acrobat – View as HTML
by O Oladunjoye – Related articlesAll 3 versions
of mergers and market concentration in the U.S. oil industry by ….. exists in the two markets, hence the negative price effect of increased ….. U.S. General Accounting Office, “Energy Market: Effects of Mergers and in the U.S. Petroleum Industry” (May 2004), United States General Accounting Office Report to

  1. [PDF]

Economic Amnesia: The Case against Oil Price Controls and Windfall …

File Format: PDF/Adobe Acrobat – Quick View
by J Taylor – Cited by 9Related articlesAll 11 versions
Eastern United States. U.S. General Accounting Office, “Energy Markets: Effects of Mergers and Market. Concentration in the U.S. Petroleum Industry,” May


The first type of analysis attempts to determine the statistical significance of the tendency

for downstream petroleum prices to increase faster than upstream prices when upstream

prices are on the rise, but to fall more slowly when upstream prices are on the decline.

Such “asymmetry” or the so-called “rockets and feathers” effect occurs most often between wholesale and retail gasoline prices, followed by crude oil-retail gasoline prices

and spot gasoline-crude oil prices. There are various theories that could explain

asymmetry, including oligopolistic coordination (e.g., signaling adherence to a collusive

agreement at the refining or retail levels), consumer search costs, and inventory

adjustment costs. However, no single theory emerges as a prevailing explanation.



Third, economists have made valiant attempts to estimate the price effects of both

horizontal and vertical domestic petroleum mergers. At the same time, this research has

been met with considerable resistance, largely over the robustness of findings to different

econometric specifications. For example, the FTC–in critiquing the GAO’s studies–

convened a panel of experts that called for additional research in order to ”test the

validity of assumptions that underlie existing methodologies used to estimate merger

price effects.”18 This debate reveals an often observed tension in economic analysis

involving controversial policy issues. Thus, the results of petroleum merger studies

(which appear to show, on balance, merger-induced increases in wholesale and retail

prices) should probably motivate even more rigorous antitrust scrutiny.19

Merger review could probably be improved within the existing framework of the antitrust

agency Guidelines. Rigorous approaches to market definition should clearly identify

refining bottlenecks. Theories of competitive harm should consider how a merger affects

the firm’s ability and incentive to adversely affect prices or output. Here, it is particularly

important to consider not only horizontal theories of harm, but vertical ones, including

the possibility of vertical foreclosure. It may be the case—as in electricity markets—for

example, that manipulation of even small amounts of strategic refining capacity may

result in very profitable anticompetitive price increases. Thus, small market shares may

not necessarily mean small market power. Simulation models are also useful for

evaluating unilateral price effects under alternative scenarios. Finally, evaluation of joint

ventures and alliances should focus on the ways that such coordination may reduce the

intensity of competition without necessarily being reflected in concentration statistics.20

18 FTC Staff Technical Report (December 21, 2004). “Robustness of the Results in GAO’s 2004 Report

Concerning Price Effects of Mergers and Concentration Changes in the Petroleum Industry,” p. 2. L. M.

Froeb, et all, (2005). “Economics at the FTC: Cases and Research, with a Focus on Petroleum” Review of

Industrial Organization 27, pp. 237.

19 Not all studies evaluate the net effect of mergers on retail prices, which would provide some sense of the

consumer welfare impact of mergers. While the magnitude of estimated price increases described by

various studies may seem small, they can translate into a significant loss of welfare in a market that

amounts to billions of dollars in annual retail gasoline sales.

20 See, e.g.., threshold issues litigated in Texaco v. Dagher, 126 S. Ct. 1276 (2006).




Schlumberger to Buy Smith for About $11.3 Billion (Update2)

February 21, 2010, 03:17 PM EST



VI. What Economic Analysis Tells Us
There is a sizable body of research on competitive issues involving the domestic
downstream petroleum industry, much of which has arisen from the debate over high
and/or volatile gasoline prices. The research addresses three major topics that relate to the
competitive implications of downstream petroleum market structures and behavioral
incentives facing firms: (1) “asymmetry” between upstream and downstream petroleum
prices; (2) effects of divorcement and open supply regulation; and (3) merger-related
price effects.
The first type of analysis attempts to determine the statistical significance of the tendency
for downstream petroleum prices to increase faster than upstream prices when upstream
prices are on the rise, but to fall more slowly when upstream prices are on the decline.
Such “asymmetry” or the so-called “rockets and feathers” effect occurs most often

between wholesale and retail gasoline prices, followed by crude oil-retail gasoline prices
and spot gasoline-crude oil prices. There are various theories that could explain
asymmetry, including oligopolistic coordination (e.g., signaling adherence to a collusive
agreement at the refining or retail levels), consumer search costs, and inventory
adjustment costs. However, no single theory emerges as a prevailing explanation.












JUNE 4, 2009

Mr. Chairman and Members of the Subcommittee, thank you for the opportunity to appear here today to discuss with you the U.S. Geological Survey’s role in studying, understanding, and assessing the unconventional gas resources of the Nation (exclusive of the Federal offshore) and the World.


Adequate, reliable, and affordable energy supplies obtained using environmentally sustainable practices are essential to economic prosperity, environmental and human health, and political stability.  National and global consumption of fossil fuels are projected to increase over the next several decades, though at a slower rate than in recent years.  The projected increase in U.S. consumption is due, in part, to greater anticipated domestic unconventional gas supplies.  The Energy Information Administration (EIA) Annual Energy Outlook 2009 projects substantial increases in domestic production of oil, natural gas, and coal, with renewable resources accounting for a rapidly increasing, but still smaller, proportion of the total energy mix under the current policy baseline. Although the impact of new policies aimed at creating a low-carbon economy may increase the speed of this transition to renewable sources, conventional energy resources are expected to remain an important component of our energy mix for some time to come.

The United States currently consumes about 21 % of the energy resources produced in the world.  Thus, the volumes, quality, and availability of domestic and foreign energy resources are of critical importance to the United States.  The Nation continues to face important decisions regarding the competing uses of public lands and offshore waters, the supply of energy to sustain development and enable growth, and the environmental effects of energy resource development.

Role of the U.S. Geological Survey

The U.S. Geological Survey (USGS) Energy Resources Program (ERP) provides the information needed to address these challenges by conducting scientific investigations of geologically based energy resources, including research and assessment on the geology of conventional oil, gas, and coal resources; emerging resources such as gas hydrates; underutilized resources such as geothermal; and unconventional resources such as shale gas and oil shale, as well as research on the environmental effects associated with energy resource occurrence, production, and (or) utilization.  The mission of the ERP is: (1) to understand the processes critical to the formation, accumulation, occurrence, and alteration of geologically based energy resources; (2) to conduct scientifically robust assessments of those resources; and (3) to study the impact of energy resource occurrence and (or) production and use on both environmental and human health.  The results from these geoscientific studies are used to evaluate the quality and distribution of energy resource accumulations and to assess the energy resource potential of the Nation (exclusive of Federal offshore waters) and the World.  (Federal offshore waters are assessed by the Minerals Management Service of the Department of the Interior.)

The results from these USGS studies provide impartial, robust scientific information about energy resources that directly supports the U.S. Department of the Interior’s (DOI’s) mission of protecting and responsibly managing the Nation’s natural resources; USGS information is used by policy and decision makers, land and resource managers, other federal and state agencies, the domestic energy industry, foreign governments, nongovernmental groups, academia, other scientists, and the public.  As one example, current findings from the USGS National Oil and Gas Assessment (NOGA) provide updated scientific information on the mean estimates for undiscovered, technically recoverable oil and gas resources underlying the onshore U.S. and State-owned waters.  They indicate that the total 47.5 billion barrels of oil and 743 trillion cubic feet of gas, respectively (Figure 1A & B).

Collectively, information from USGS research advances the scientific understanding of energy resources, contributes to plans for a balanced and secure energy future, and facilitates the strategic use and evaluation of resources.

USGS National Resources Research and Assessment Activities

The overall goal of USGS domestic energy activities is to conduct research and assessments of all geologically based energy resources.  This includes undiscovered, technically recoverable oil and natural gas resources, both conventional and continuous (also referred to as unconventional), of the United States (exclusive of the Federal offshore).  These are resources that have yet to be found (drilled), but if found, could be recovered using currently available technology and industry practice (without regard to economic viability).  The purpose of USGS assessments is to develop robust, geology-based, statistically sound, well-documented estimates of quanti­ties of energy resources having the potential to be added to reserves, and thus contribute to the overall energy supply.  The USGS uses resource assessment methodologies that are thoroughly reviewed and externally vetted so as to maintain the transparency and robustness of the assessment results.

In recent years, the USGS has distinguished between conventional and continuous petroleum accumulations for pur­poses of research and resource assessment (Figure 2).  Briefly stated, conventional accumulations are described in terms of discrete fields or pools localized in structural or stratigraphic traps by the buoyancy of oil or gas in water. In contrast, continuous accumulations are petroleum accumulations (oil or gas) that have large spatial dimensions and indistinctly defined boundaries, and which exist more or less independently of the water column.  Examples of continuous accumulations are shale gas and coalbed gas, which are among the fastest growing domestic energy resources.

The current USGS effort to update national (onshore and State waters) assessments of oil and gas resources is done in support of the Energy Policy and Conservation Act (EPCA) Amendments of 2000 (P.L. 106–469 §604).  The USGS assesses the potential volumes of conventional and continuous (unconventional) resources (e.g. coalbed gas, shale gas, tight gas sands) in each priority province using established, externally reviewed and vetted methodologies, and provides this information to the appropriate land and resource management agencies for subsequent analysis.  The Energy Policy Act of 2005 (P.L. 109-58) re-authorized EPCA 2000 assessment activities by the USGS, emphasizing the unique role of the USGS, and specifically mandated that “the same assessment methodology across all geological provinces, areas, and regions [be used] in preparing and issuing national geological assessments to ensure accurate comparisons of geological resources.”  The current mean estimate for the United States as a whole for undiscovered, technically recoverable continuous gas resources is 364 trillion cubic feet (Figure 3).

The amount of undiscovered, technically recoverable resources changes over time.  There are several reasons for this, including scientific and technological developments regarding petroleum resources in general, improvements to the geologic understanding in numerous settings, and reserve growth.  These advances in geologic understanding, as well as changes in technology and industry practices, necessitate that resource assessments be periodically updated.  This is especially true for continuous (unconventional) resources.  New technological developments increase the recoverability of this challenging resource, and our geologic understanding of these resources is evolving.  One example of this change is the recently updated USGS assessment of the Bakken Formation in the U.S. portion of the Williston Basin.  This assessment, released in 2008, shows an estimated 3.0 to 4.3 billion barrels of undiscovered, technically recoverable, continuous oil compared to the agency’s 1995 mean estimate of 151 million barrels of oil.  Assessments of unconventional natural gas resources, including the Barnett Shale, the Marcellus Shale, and others, have shown the same type of increase as our understanding of the geology increases.  Much of the technology developed for production of the gas in the Barnett Shale is being used to extract the oil in the Bakken Formation, and these technological advances accounted for the large change in what was considered technically recoverable.  The Barnett Shale Newark East field now ranks second in the United States in terms of annual gas production (EIA, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/current/pdf/appb.pdf ). Cumulative gas production from January 1993 to January 2006 from the Barnett Shale Newark East field was about 1.8 trillion cubic feet; in 2005, gas production was about 480 billion cubic feet compared to less than 11 billion cubic feet  in 1993 (Texas Railroad Commission, 2006, available at http://www.rrc.state.tx.us/data/fielddata/barnettshale.pdf ).

U.S. Geological Survey International Energy Studies

Our Nation depends heavily on imported energy resources: about 57 percent of the oil and 16 percent of the natural gas consumed in the United States come from imports.  Given the significance of imported oil and gas to the U.S. energy mix, scientifically valid,  unbiased assessments of the world’s remaining endowment of petroleum accumulations are very important.  For this reason, global petroleum resource assessments are a core USGS research activity and have significant global visibility.  The USGS world oil and gas resource estimates are used as a standard reference by many organizations including the Energy Information Administration (EIA) and the International Energy Agency (IEA).

The overall objectives of USGS studies of international petroleum resources are to continue providing high-quality, comprehensive petroleum assessments and to update previous assessments as needed.  A major focus of recent USGS research in this area is the global Circum-Arctic Resource Appraisal, the primary emphasis of which is to provide a comprehensive, unbiased probabilistic estimate of potential future additions to conventional oil and gas reserves in the high northern latitudes.  The Arctic is an area of high petroleum resource potential, low data density, high geologic uncertainty, and sensitive environmental conditions.  The assessment is the first publicly available petroleum resource estimate of the entire area north of the Arctic Circle. Results indicate that the area north of the Arctic Circle has an estimated mean of 90 billion barrels of undiscovered, technically recoverable oil, 1,670 trillion cubic feet of technically recoverable natural gas, and 44 billion barrels of technically recoverable natural gas liquids in 25 geologically defined areas thought to have potential for petroleum. These resources account for about 22 percent of the undiscovered, technically recoverable resources in the world. The Arctic accounts for about 13 percent of the undiscovered oil, 30 percent of the undiscovered natural gas, and 20 percent of the undiscovered natural gas liquids in the world. About 84 percent of the estimated resources are expected to occur offshore.

Outside of the United States, the USGS has conducted assessments on conventional oil and gas resources only, as little data exist on global continuous (unconventional) accumulations.  Currently the USGS is conducting a screening exercise to evaluate the availability of information for resource estimates of continuous petroleum resources outside the United States.  Continuous resources have the potential to significantly contribute to global petroleum resources, but scientifically-vetted characterization and quantitative estimates of these resources must be available before their true potential can be evaluated.


During the next decade, the Federal Government, industry, and other groups will need to better understand the domestic and global distribution, genesis, use, and consequences of using geologically based energy resources to address national security issues and climate change, manage the Nation’s domestic supplies, predict future needs, anticipate as well as guide changing patterns in use, facilitate creation of new industries, and secure access to appropriate supplies.  Energy resources research and assessments are a traditional strength of the USGS, and these activities provide impartial, robust information necessary for the many needs just outlined.  As the Nation’s energy mix evolves, the USGS will continue to adapt its research and assessment portfolio to include a comprehensive suite of energy sources that reflects the highest priority needs of the nation.  USGS resource assessments and research are an integral part of the public and government discourse about the energy resource future of the Nation, and allow science to inform, advise, and engage decision makers.  The USGS stands ready to assist Congress as it examines these challenges and opportunities.

Thank you for this opportunity to provide an overview of USGS research and assessments of natural gas and other energy resources.  I would be happy to answer your questions.



Figure 1. Current mean estimates from the USGS NOGA Project for undiscovered, technically recoverable resources of (A) oil and (B) natural gas.  Additional information from the USGS NOGA project is available from: http://energy.cr.usgs.gov/oilgas/noga/ .

Figure 2. Conceptual diagram illustrating the different geologic settings between conventional and continuous resource accumulations.

Figure 3.  Current mean estimates from the USGS NOGA Project for undiscovered, technically recoverable continuous natural gas.  Additional information from the USGS NOGA project is available from: http://energy.cr.usgs.gov/oilgas/noga/ .

(From -)


Statement of Douglas Duncan, Research Geologist, June 4, 2009 Word
Before the Committee on Natural Resources, Subcommittee on Energy and Mineral Resources on the Unconventional Fuels, Part I: Shale Gas Potential.