We've
lowered our estimate of the marginal cost of domestic natural gas from
$6.50 per thousand cubic feet to $5.40 per mcf, driven primarily by an
updated analytical approach. Because our upstream valuation methodology
incorporates an out-year marginal cost-based view on oil and gas prices,
it follows that a reduction in marginal cost results in a revaluation
of our gas-weighted upstream energy coverage universe. For those firms
most leveraged to gas production, our fair value estimates have
decreased 10%-15%. However, oil and liquids exposure provides insulation
from any meaningful change to fair value estimates for the majority of
our upstream coverage list. Our valuations also reflect our current
midcycle view on oil, incorporating $95 per barrel West Texas
Intermediate and $99 per barrel Brent. In addition, we assume that North
American natural gas liquids composite prices trade between 40% and 50%
of crude oil throughout our forecast period.
We remain bullish
on domestic natural gas and continue to see considerable upside to
current gas prices. Our analysis indicates that Henry Hub gas prices
tend to track marginal cost quite well over longer time intervals,
strongly suggesting a rebound from today's $3.70 per mcf within a few
years. This is reflected in our stock calls, as for the most part our 4-
and 5-star stocks remain just that, even after updating our models with
a lower out-year gas price assumption. We continue to view Ultra
Petroleum UPL and Devon Energy DVN as the most attractive gas-weighted names, Apache APA and Canadian Natural Resources CNQ as the most attractive mixed-oil/gas stocks, and Suncor SU and Occidental Petroleum OXY as the most attractive oil-weighted firms.
Faced
with a tightening resource market, ConocoPhillips made significant
acquisitions over the past decade to boost reserves and increase
production. The ensuing fall in commodity prices made those acquisitions
appear poorly timed, however. As a result, management changed course in
past years by selling assets and reducing investment. In May, it took
the final step by spinning off the downstream assets into a separate
company, Phillips 66 PSX. Now the company is turning its focus to growth.
After the spin-off of its downstream businesses, ConocoPhillips ranks
as the largest U.S.-based independent exploration and production firm.
Based on production volumes, it is nearly twice as large as its closest
peer. However, with its size come challenges, most notably
ConocoPhillips' low growth rate relative to its new peer group. With a
target of 3%-5% compound annual growth, ConocoPhillips matches up well
with its former integrated peers, but falls short with respect to its
smaller rivals. In this respect, it closely resembles Marathon Oil MRO,
a former integrated now operating as an independent E&P, with a
growth target in the low single digits. Both also have diversified asset
profiles--onshore, offshore, LNG, oil sands, and so on--which are
potentially less attractive compared with peers with much more
concentrated portfolios.
That is not to say that ConocoPhillips has no opportunities to
increase production and add reserves. In addition, future production
additions will largely add liquids volumes or natural gas volumes from
liquefied natural gas, or LNG, projects, whose prices are indexed to
oil. In North America, ConocoPhillips plans to drive production growth
through development of its positions in the Eagle Ford, Permian, and
Bakken, as well as its Canadian SAGD operations. Internationally, growth
will come from major projects in the North Sea, Malaysia, and its LNG
project in Australia. In addition to contributing production of about
550 mboe/d of production by 2016, these projects are also higher-margin
(assuming the current commodity price environment holds) versus current
producing assets.
Ultimately, though, ConocoPhillips' size will dilute the impact of
these projects, as total production is expected to be 1.8 mmboe/d in
2016. The rest of the production will come from the lower-quality assets
that resulted in ConocoPhillips' weaker upstream returns compared with
its integrated peers. As a result, the company would probably benefit
from a continuation of asset sales beyond its current planned program of
$8 billion-$10 billion over the next 12 months. The asset sales would
also go toward shoring up the balance sheet and ensuring continued
investment in the event of a drop in commodity prices.
We're
maintaining our fair value estimate of $52 per share after lowering our
long-term natural gas price assumption to $5.40/mcf from $6.50/mcf. The
lower natural gas prices reduces our fair value estimate by $2 per
share, all else equal. However, we have increased our estimates for 2013
sales proceeds after the sale of a 8% stake in Kashagan for $5 billion
which offsets the reduction. Our blended valuation (EBITDAX multiple and
discounted cash flow-based) implies a multiple of 3.7 times 2013 EBITDA
forecast of $22.4 billion.
We forecast ConocoPhillips to meet its production growth targets,
which include a compound annual growth rate of 3%-5% over the next five
years, and production of 1.8 million boe/d in 2016. However, we expect
production volumes to remain flat to down in 2013 as new production will
unlikely offset natural declines and dispositions. Sales of
lower-quality assets, particularly high-cost domestic natural gas, may
lower volumes but should result in an overall higher-quality portfolio.
Primary growth drivers include the aforementioned Lower 48
unconventional plays, Canadian SAGD developments, and select
international projects.
In our discounted cash flow model, our benchmark oil and gas prices
are based on Nymex futures contracts for 2012-14. For natural gas, we
use $2.87 per thousand cubic feet in 2012, $4.08 in 2013, and $4.31 in
2014. Our long-term natural gas price assumptions for 2014 and 2015 are
$5.40. For oil, we use Brent prices of $112 per barrel in 2012, $108 in
2013, and $104 in 2014. Our long-term oil price assumptions for 2014 and
2015 are $95 and $98, respectively. We assume a cost of equity of 10%,
and a WACC of 8.5%.
Persistently
low oil and gas prices would hurt cash flow and force ConocoPhillips to
reduce its capital plans or raise debt to fund growth. The company's
large projects run the risk of delays, cost inflation, and falling
commodity prices, which could ruin their economics. Global operations
and partnerships with national oil companies expose the company to the
threat of expropriation of assets and modification of contract terms by
governments.
Management & Stewardship
Ryan
Lance, previously senior vice president of E&P, international,
assumed the chairman and CEO role of ConocoPhillips after the spin-off.
Lance's 26 years of industry experience and background in petroleum
engineering should serve him well as ConocoPhillips begins life as an
independent E&P.
His strategy appears to be a bit of a departure from years past when
efforts focused on a shrink-to-grow strategy. There will be some
additional asset sales in the next year, but at the same time management
is ramping up capital spending to drive production growth. Time will
tell if this strategy is successful. While ConocoPhillips does have some
attractive assets that warrant investment, the recent strategy of
increasing shareholder returns and selling assets has proved successful
and could have been continued. While shareholder returns will remain a
priority, management is giving itself little room for error with its
capital plan. As a result, spending may have to be curtailed if
commodity prices fall, resulting in lower growth than targeted.
Overview
ConocoPhillips
holds about $1.3 billion in cash and $2.5 billion in restricted cash at
the end of the third quarter. During the quarter it repaid $2 billion
in debt, reducing its debt/capital ratio to 31% from 33%. The restricted
cash could go toward additional debt repayment to get the company to
its long-term target of 25-30%
Profile:
ConocoPhillips
is a U.S.-based independent exploration and production firm. In 2011,
it produced 867,000 barrels per day of oil and natural gas liquids and
4.5 billion cubic feet a day of natural gas, primarily from the United
States, Canada, Norway, and the United Kingdom. Proven reserves at
year-end 2011 stood at 8.4 billion barrels of oil equivalent, 41% of
which are natural gas.
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