Royalty relief, not industry windfall, benefits US - Oil & Gas Journal, September 11-17 issue
An economic study indicates that deepwater Gulf of Mexico properties have
not been a windfall for the oil and gas industry, even with the Deep Water
Royalty Relief Program.
Although the program has spurred a leasing boom in deepwater Gulf of Mexico, by our
calculations, the industry is yet to experience a calendar year of positive after-tax cash flow.
One benefit of the royalty relief program has been that it has diverted
billions of dollars, which otherwise might have gone overseas, to bonus
payments, lease rentals, seismic, geological studies, drilling, construction,
and operations in the Gulf of Mexico, thus creating thousands of US jobs.
But the expiration of the automatic Deep Water Royalty Relief Program on
Nov. 28, 2000, unless extended, may well end the leasing boom in the deepwater
Gulf of Mexico that has surpassed the expectations of government and industry.
The leasing and exploration of tracts in water depths greater than 1,000
ft began in 1974. From 1974 through 1999, industry has invested more than
$35 billion for leasing, evaluating, exploring, developing, and operating
in deepwater. Of this $35 billion, more than $15 billion are yet to be
recovered.
Twenty-six years is a long time to wait for positive cash flow, with payout
projected to be at least 3 years away.
With robust prices, 2000 might well be the first year that the industry's
deepwater exploitation realizes a positive annual after-tax cash flow
Royalty relief
The automatic royalty relief for deepwater may expire, although it is believed
that the US Minerals Management Service (MMS) plans to continue the discretionary
royalty relief portion of the program.
Under the discretionary program, MMS has authority to grant royalty relief
on an ad hoc basis when it concludes that royalty relief is economically
necessary for the development or continuation of a producing property.
The problem with such a discretionary program is that no company can incorporate
the suspension of royalties into its preleasing economics. As a consequence,
the discretionary portion does nothing to stimulate leasing and causes
companies to hesitate in entering or continuing deepwater operations.
If oil and gas are found in subcommercial quantities, the discretionary
portion of the program might allow the project to go forward, but it does
nothing to stimulate exploration.
Under the automatic suspension of royalties, the program suspends royalties
for any new leases in water deeper than 200 m issued within 5 years of
Nov. 28, 1995. This automatic suspension of predefined royalty levels,
based on water depth, allows companies to incorporate royalty relief into
their exploration economics before leasing or exploration drilling.
Deepwater production
According to the US Department of Interior, Gulf of Mexico oil production
could increase to 1.8 million b/d in 2001, nearly double the oil production
from the Gulf of Mexico in 1995, when the royalty relief act was enacted.
Deepwater production facilities are expensive and the economics of spending
more than $1 billion on a single facility challenge even the largest of
companies.
For example, ExxonMobil Inc: s Hoover/Diana platform, in 4,800-ft water,
cost $1.1 billion, and Shell Oil Co.'s Ursa platform came in at $1.45 billion.'
Only the largest oil companies have the financial ability to handle the
requisite capital programs to chase and develop deepwater reserves.
The question facing the Department of the Interior is how to make the Gulf
of Mexico competitive with other provinces around the world?
Sizable expenditures are being spent for finding oil and gas in deepwater
basins around the world. ExxonMobil's senior vice-president for exploration,
Harry Longwell, observed that deep water is the hottest exploration play
in the world right now Shell and ExxonMobil expect to spend about $1 billion/year
each on deepwater projects.
To date, about 40 billion bbl of oil have been discovered in the world's
deepwater areas. Both ExxonMobil and Shell suggest that this amount could
well grow to 100 billion bbl or about 10% of current estimated recoverable
oil reserves.'
The current Gulf of Mexico developments are primarily standalone projects.
But to allow for the full development of its deepwater areas, it is critical
that a suf ficient infrastructure be installed to allow for exploration
and development of smaller fields and satellite accumulations.
The policy implications for continuing automatic royalty relief relate
directly to whether the economics associated with field size expected today
in deepwater Gulf of Mexico justify commercial production.
Our analysis reveals that without automatic royalty relief many deepwater
Gulf of Mexico projects simply will not be drilled or, for that matter,
developed. And the choking off of such exploration and related development
will limit the installation of an infrastructure, thus further retarding
development.
This analysis of the deepwater Gulf of Mexico is from the viewpoint of
an exploration manager making recommendations as to where to allocate limited
capital, or a senior executive staff or board of directors in choosing
where to invest.
Deepwater prospects
Norland Consultants, in its latest deepwater research report, estimates
that some $76 billion could be spent in deep water over the next 5 years,
mostly off Brazil, West Africa, and Gulf of Mexico. West Africa has some
of the best prospects and will capture the lion's share of the capital
investment.
Fig. 1 a illustrates that average field size in deepwater Gulf of Mexico
is substantially smaller than off Nigeria, Angola, or Brazil. Besides field
size, it should be noted that deepwater Gulf of Mexico is a more mature
play The play began in the 1970s, became popular in the 1980s, and boomed
in the 1990s.
Deepwater plays in Brazil and West Africa are more recent, while deepwater
activity in the Gulf of Mexico has entered mid-life (Fig. 1b).
As expected, average field size decreases as a play matures. Although large
fields will likely still be found in deepwater Gulf of Mexico, these large
discoveries will increasingly become rare.
When comparing anticipated exploratory deepwater results among competing
regions, the relative impact of the country's fiscal regime is extremely
important.
A recent Wood Mackenzie Consultants, Edinburgh, study indicates that while
the expected economic benefit per barrel of reserves discovered in the
deepwater Gulf of Mexico is greater than Angola, Brazil, and Nigeria, the
significantly greater reserves per discovery in these three areas yields
far better economics (Fig. 1c).
The policy question for the MMS and the business decision for the oil industry
is whether deepwater Gulf of Mexico economics justify continued enthusiasm
in light of the current expected field size and, if not, how important
is royalty relief?
Nearly 1,200 deepwater leases will be expiring between 2000 and 2006 (Fig.
2a).The discussion over extending royalty relief, to a large extent, involves
leases that were recently held by industry and that did not prove successful
or failed to be highgraded and drilled.
From Fig. 2a, one should note that deepwater Gulf of Mexico has reached
mid-life. The leases that will come up for bid in the near term will consist
of acreage that industry has either reviewed and decided not to acquire,
been acquired, highgraded and drilled, or been acquired, highgraded, and
not drilled.
Table 1 lists the number of leases expiring and ultimately available for
re-leasing. These number about 1,326 through 2006. It is interesting to
note that the US collected $660.6 million from bonus payments from leases
that contained royalty relief and will be relinquished by 2006 after being
evaluated and not drilled or drilled and released.
A substantial number of the leases have and, with some extrapolation, will
be drilled by the time these leases expire. Many will have multiple wells
drilled. Table 1 illustrates that the deepwater Gulf of Mexico is not virgin
acreage but rather an area that has received significant evaluation, highgrading,
and drilling.
To raise the price of "used" acreage by eliminating automatic royalty relief,
in the face of increasing demand and decreasing US production, does not
necessarily fit with perpetuating a high level of activity and investment
in the competitive environment.
In a competitive environment, the US ignores competing oil and gas environments,
at its peril.
The US has been successful in attracting a number of the foreign super-majors
into the deepwater Gulf of Mexico and, more recently, has attracted several
large foreign independents. Pierre Jungels, the chief executive officer
of Enterprise Oil plc, the UK's largest independent, has invested substantial
sums exploring and now developing deepwater Gulf of Mexico projects.
Enterprise Oil appreciated the competitive environment of the Gulf of Mexico
created, in part, as a consequence of royalty relief. In considering the
benefits of automatic royalty relief, Jungels says the UK, Norway, and
Ireland have removed royalty from their offshore tax system on the ground
that it is a regressive tax that is detrimental to development.
"Clearly the competition for the US is just across the Atlantic."
Major companies
It is interesting to observe that the super majors have been in the deepwater
Gulf of Mexico for 2 decades. As with many new plays, the early entrants
captured some of the best acreage. BP, Shell, and ExxonMobil hold a commanding
acreage position and the lion's share of the deepwater production in the
Gulf of Mexico.
A few large companies are dominating worldwide deep water. Although 29
operators are currently considering deepwater developments, only seven
companies hold 77% of these deepwater developments, as follows: BP, Shell,
ExxonMobil, TotalElfxina, Chevron Corp., Texaco Inc., and Petrobras.
As a policy issue, is the US effectively reserving the deepwater Gulf of
Mexico for the largest companies or will the US apply the business acumen
to allow fields that are below the threshold levels of the largest companies
to be commercially viable and developed by the independent oil and gas
sector?
Exploration hot spots
The recent deepwater Gulf of Mexico lease sales have witnessed a falloff
in the number of leases acquired by the super majors, which may portend
a de-emphasis of the deepwater Gulf of Mexico by these companies.
It is interesting to note that the Gulf of Mexico did not make the top
ten list of exploration hot spots in the most recent Robertson Research
International survey.
Robertson Research, which asks international oil companies to rate their
level of interest in new global exploration and production ventures in
146 countries, found the countries having the most interest were Libya,
Iran, UK, Australia, Algeria, Iraq, Indonesia, Angola, Brazil, and Egypt.
Gulf of Mexico economics
We recently completed an economic evaluation, focused on water depths in
excess of 1,000 ft, that attempted to capture both exploration and production
expenditures as well as production and revenues on a historic and projected
basis.
Public record data, published industry estimates, press release data as
well as selected commercial services were utilized to capture the economic
results for all defined developments as of Jan. 1, 2000. Future oil and
gas prices were derived from prices implicit in the Nymex forward curves.
The analysis shows that deepwater Gulf of Mexico has by no means been a
windfall to the industry As previously mentioned, more than $15 billion
in expenditures have yet to be recovered and 2000 might well be the first
year that the industry realizes positive annual after-tax cash flow (Fig.
3 a) .
Projected after-tax return, including all reasonably defined developments,
is only 9.4% on a money-of the-day basis. The real return, using the annual
GNP deflator, is only 7.2 % after tax.
Industry expectations are clearly based upon returns well in excess of
historic results and incremental returns on successful projects can and
will be comfortably in excess of 30%.
Through the execution of relative competitive advantage, Shell, BP, and
ExxonMobil have dominated the deepwater Gulf of Mexico, participating at
least in part in nearly every development in excess of 150 million boe.
Their domination in early leasehold positions has been well documented.
Excluding these three companies, the aggregate returns in the deep water
for the balance of the industry are 4.8% nominal and 3.0% real. Companies
earning no more than 5% returns did not overlook the added incentive implicit
in deepwater royalty relief.
The aggregate returns of the largest three, which used to be five, are
slightly higher than the industry total, but still less than 10% nominal.
Although the poor compound returns are primarily attributed to decades
of negative cash flows, projected peak production at currently robust oil
and gas price assumptions over the next decade exceed all but the most
optimistic of forecasts from previous years.
A similar analysis made 2 years ago would not have anticipated any aggregate
positive return for the industry and, if oil and gas prices fall, our rate-of
return analysis will look optimistic.
Perhaps the most significant impact of royalty relief is that it allows
a greater number of reserve accumulations to become economically attractive.
With a relatively mature play the expected average field size distribution
continues to diminish. Without presumptive royalty relief, the expectations
of finding economic accumulations diminish even faster.
Fig. 3b shows the impact of royalty relief on field size. In 1,200-m water,
the minimum economic field size to generate a 15% before-tax return decreases
from 92 million to 79 million boe. For most industry participants, presumptive
returns in excess of 15% before-tax are required before capital will be
allocated to a project or program.
The MMS currently projects that 10.2 billion boe remain to be discovered
in field sizes of less than 100 million boe in water depths between 800
and 3,000 m. If the impact of royalty relief results in a 20% reduction
in minimum economic field size, an incremental 1.6 billion boe could potentially
be developed that otherwise would go unexploited.
The nature of the existing royalty relief structure ensures that, in relative
terms, it mostly impacts marginal field developments. Encouraging additional
infrastructure makes even more satellite accumulations economic.
A 50% increase in the number of projected developments of 15-50 million
boe accumulations would add an additional 1.3 billion boe that otherwise
would not be developed according to MMS potential reserve estimates. Consequently,
nearly 3.0 billion boe might well remain unexploited if the royalty relief
program is discontinued.
The program provides a valuable incentive without creating an economic
windfall. As shown in Fig: 3b, the pretax rate of return for a 100-million-bbl
field increases to 9.8 % from 5.2%, while for a 140 million-boe field,
the rate of return increases to 18.5% from 14.5%.
When evaluating the prospective economics of a potential distribution in
anticipated prospect reserves, returns of 9.818.5% with royalty relief
compared to 5.2-14.5% without it may be the difference between funding
a prospect and moving on to other prospects outside of the US.
Those opposed to the automatic royalty relief portion of the program might
argue that as long as the MMS is authorized to grant royalty relief on
a discretionary basis, marginal fields can be granted royalty relief on
an ad hoc basis and made commercial.
No doubt some fields will be handled in that way, but the incentive to
explore will be substantially reduced without the automatic provision because
no company will incorporate discretionary ad hoc royalty relief into exploration
economics.
If exploration is less, less infrastructure will be installed, thus preventing
smaller fields and satellites to be drilled.
The Independent Petroleum Association of America (IPAA) has stated that
independents hold 42% of the active leases in the deepwater Gulf of Mexico
and it is becoming increasingly worried about the extension of the royalty
relief program.
Earl Sims, vice-chairman of IPPA's off shore committee, says without the
continuation of deepwater royalty relief, "no doubt there will be less
activity. It represents a significant incentive."'
Ben billion, IPAA vice-president of public resources says "Without incentives,
marginal fields in 200-800 m of water, which is the traditional stomping
grounds for independents, likely will fail to reach the economic threshold
for development."3
Dillion predicted that independents likely will be discouraged from evaluating
their leases if adequate incentives are not adopted. The IPAA is concerned
that without royalty relief, leasing activity will fall and the industry
will find it difficult to meet the projected 29 tcf of natural gas demand
forecasted in the US by 2010.3 Failure to extend the program will certainly
result in fewer leases, fewer exploration wells, and less oil and gas discovered.
The US Energy Information Administration (EIA) in an extensive analysis
performed on the economics of deepwater royalty relief, concluded that
"the program may be strongest in reducing the likelihood of losses as an
important element in promoting additional investments in deepwater projects".
The EIA found that the "royalty relief program increases the expected value
return from the deepwater projects. However, it also enhances the perceived
returns in a fundamental way that is more readily apparent when such a
project is assessed under conditions of uncertainty."
The continuation of the automatic royalty relief is unlikely to have a
cost. For example, incremental bonuses have, to date, far outweighed the
financial impact of royalty suspension.
If history is a guide, similar bonus dif ferentials can be expected if
the automatic royalty suspensions are continued.
Moreover, projects benefiting from royalty relief will more quickly become
taxable and give back to the US Treasury Department some of the benefits
bestowed by the royalty relief program.
Beyond the financial benefits of increased bonus and taxes, it can be expected
that there will be an increase in rental payments, to say nothing of the
associated, likely benefits of job creation and more oil and gas production.
References
1. Wall Street Journal, July 3, 2000.
2. Hart's E&P, Deep Water Technology Supplement, July 2000, p. 8.
3. Platt's Oilgram News, May 4, 2000, p. 4.
Andrew B. Derman
Thompson & Knight LLP Dallas
Gregg Jacobson
Randall & Dewey Inc. Houston
The authors
Andrew B. Derman is a senior partner with Thompson & Knight LLP in Dallas.
He heads the firm's International Energy Practice group. He was formerly
an executive with Oryx Energy Co, Derman holds a BA from NewYork University
and a JD from Temple University Law School and is board certified in Texas
in the field of oil, gas, and mineral law.
Gregg Jacobson is vice-president of Randall & Dewey Inc., a Houstonbased
transaction advisory firm. He heads the firm's petroleum advisory group
that provides strategic and technical consulting to the upstream oil and
gas industry. He previously was the director of business development
and planning for Oryx Energy Co. Jacobson has a BS in petroleum engineering
from Texas A&M University. |
