Legislature(2011 - 2012)SENATE FINANCE 532
03/15/2012 01:00 PM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB192 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 192 | TELECONFERENCED | |
| + | TELECONFERENCED |
SENATE FINANCE COMMITTEE
March 15, 2012
1:05 p.m.
1:05:34 PM
CALL TO ORDER
Co-Chair Stedman called the Senate Finance Committee
meeting to order at 1:05 p.m.
MEMBERS PRESENT
Senator Lyman Hoffman, Co-Chair
Senator Bert Stedman, Co-Chair
Senator Lesil McGuire, Vice-Chair
Senator Johnny Ellis
Senator Dennis Egan
Senator Donny Olson
Senator Joe Thomas
MEMBERS ABSENT
None
ALSO PRESENT
Senator Cathy Giessel; Senator Joe Paskvan; Senator Hollis
French; Gerald Kepes, Partner and Head of Upstream and Gas,
PFC Energy.
PRESENT VIA TELECONFERENCE
Janak Mayer, PFC Energy, Washington, DC.
SUMMARY
SB 192 OIL AND GAS PRODUCTION TAX RATES
SB 192 was HEARD and HELD in committee for
further consideration.
SENATE BILL NO. 192
"An Act relating to the oil and gas production tax;
and providing for an effective date."
1:06:01 PM
GERALD KEPES, PARTNER AND HEAD OF UPSTREAM AND GAS, PFC
ENERGY, introduced himself.
Mr. Kepes discussed the PowerPoint Presentation:
"Discussion Slides: Alaska Senate Finance Committee" (copy
on file). He stated that since the current day's morning
meeting, he had conducted some global context analysis for
energy and petroleum and upstream investment. He stated
that there was a focus on the Alaska Clear and Equitable
Share Act (ACES); different cost-producing scenarios; and
global comparison of average and marginal government take.
Mr. Kepes discussed slide 31, "ACES versus CS SB 192." He
stated that the slide displayed the differences between
ACES and CS SB 192. He explained that production tax was
not bracketed in either case. He furthered that CS SB 192
decoupled oil and gas. He noted the difference in the rates
for the production tax: ACES had a maximum of 75 percent
and CS SB 192 had a maximum of 60 percent. He stated that
the progressivity for ACES was 0.40 percent, and the
progressivity for CS SB 192 was 0.35 percent. He added that
CS SB 192 had an allowance for new oil.
JANAK MAYER, PFC ENERGY, WASHINGTON, DC (via
teleconference), stated that CS SB 192 also held a flaw
related to the minimum rate of production tax value at 10
percent of gross value for large producers. He explained
that there would be a presentation of that analysis.
Mr. Kepes looked at slide 32, "ACES (Existing Producer)."
He explained that the slide represented a 2000 barrels per
day producer. He stated that the government take, displayed
in the upper right hand table, varied from roughly 68
percent up to 81 or 82 percent as oil prices rose.
1:11:20 PM
Mr. Kepes discussed slide 33, "CS SB 192 (Existing
Producer)." He noted similar producing characteristics with
ACES. He pointed out some slight variations between ACES
and CS SB 192: the peak of government take under CS SB 192
lowered from 83 percent to 79 percent; and the project net
present value of producers under CS SB 192 rose slightly
for existing producers.
Mr. Kepes looked at slide 34, "ACES (New Development)." He
stated that the slide was an analysis of the higher cost
development, peaking at 10,000 barrels per day representing
a reserve size of approximately 65 million barrels, at $100
a barrel. He noted that the total government take started
at 75 percent and peaked at 85 percent.
Mr. Kepes discussed slide 35, "CS SB 192 (New
Development)." He noted that the government take for new
development was 80 percent at its peak. He stated that both
new development projects were fairly marginal at $100 per
barrel, and it did not change from ACES to CS SB 192.
Co-Chair Stedman requested an explanation of each quadrant
displayed in the slide. Mr. Kepes explained that the upper
left hand quadrant represented the cash flow analysis. He
pointed out the periods of negative revenue represented the
initial capital expenditures (CAPEX) and operations
expenditures (OPEX) for a particular project. He noted that
the peak CAPEX in the third year of development was $300
million, which was calculated after the capital credits
were applied. He pointed out that the operating costs
extended for the lifetime of the field. He furthered that
the black line represented the after tax cash flow (ACTF).
The upper right hand portion of the slide was a table that
coincided with the cash flow analysis graph. He noted that
the table displayed a summary at $40, $60, and $100 per
barrel; the net present value of the project investment to
the investor; and the internal rate of return (IR) to the
investor. At $100 per barrel, the project represented a net
present value of $12 million, and an IR of 10 percent. He
stressed that at $100 per barrel, from the point of view of
the investor, it was a relatively marginal project. The
lower left hand corner graph displayed a breakdown of the
different components of government take. The red
represented the royalty, the yellow represented production
tax, the light blue represented the property tax, the green
represented the state corporate income tax (CIT), and the
dark blue represented the federal CIT.
1:16:42 PM
Co-Chair Stedman wondered what the lower-right-hand corner
represented. Mr. Kepes replied that it was a normalized
representation of the level and composition of relative
government take. He stated that the fiscal system breaks
down at $40 to $60 per barrel, because the price would be
too low to maintain at the particular fiscal system. He
furthered that as the price of oil rose; the royalty was a
progressively smaller percentage of the overall government
take. He pointed out the increase of the contribution of
the production tax, because of the where the base was
located, and the "stepping" at the upper price ranges.
Mr. Kepes stated that the same quadrant structure on the
slide would be used throughout the presentation.
Mr. Kepes looked at slide 36, "Progressivity Impact on New
Development Project Economics." He stated that the graph on
the left hand side of the slide represented a comparison
ACES and predecessor regimes (actual and proposed). The
right hand side graph displayed a comparison with ACES and
CS SB 192 with bracketed amendments.
Co-Chair Stedman wondered if the x-axis was ANS West Coast.
Mr. Kepes responded that it was ANS West Coast at $100 per
barrel, with a net present value in millions of dollars for
the investor.
Co-Chair Stedman requested an analysis of PPT and its
evolution. Mr. Kepes thanked the chairman, and agreed to
provide that information.
Mr. Kepes discussed slide 37, "New Oil Allowance:
Incremental Production on a Declining Base":
Central to understanding the impact of the "allowance
for 'new oil'" is an understanding of the impact of
new source production on a company's total production
volumes, when that new source production is added to a
declining base portfolio.
The charts assume a 6 percent decline rate for an
existing North Slope producer currently producing 200
million barrels per day (mb/d), and examine
hypothetical new source projects that peak at 10 mb/d,
50 mb/d and 100 mb/d respectively(on a working
interest basis).
Given the pace at which such projects typically reach
peak production, only the 100 mb/d peak production new
source development is actually capable of adding
production that is incremental to prior years'
volumes.
1:23:49 PM
Co-Chair Stedman wondered why 200 mb/d was used in the
analysis. Mr. Kepes replied with slide 38.
Mr. Kepes looked at slide 38, "A Hypothetical 100 mb/d
(Working Interest) Development":
A new source development that produced 100 mb/d at
peak for a working interest partner would be a very
significant new development. By way of comparison,
Kuparuk, the second largest field in North America,
peaked at approximately 320 mb/d gross production.
-This represented working interest production to
ConocoPhillips (the operator and majority shareholder)
of 170 mbo/d.
-Kuparuk took 11 years (from 1981 to 1992) to reach
this peak level of production.
Co-Chair Stedman announced that there would be discussions
about any particular tax structure's probability of
producing great amounts of oil. Mr. Kepes replied that the
prospectivity of finding an on-shore field that could
produce 320 mb/d was fairly low. It was more likely that
new field prospectivity would be substantially low.
Mr. Kepes discussed slide 39, "Assumptions":
The following analysis assumes
1. A 6 percent base portfolio decline, in the case of
a producer currently producing 200 mb/d.
2. Costs for the base production portfolio of:
-$12/ flowing bbl operating expenditure
-$5/ flowing bbl maintenance capital expenditure
3. Costs for the 100 mb/d (working interest) New
Development project of:
-$13/ flowing bbl operating expenditure
-$13/bbl reserves development capital expenditure
-$1/ flowing bbl maintenance capital expenditure
4. These costs are deliberately somewhat lower than
the previously referenced 10 mb/d new development,
since the hypothetical development modeled is
significantly larger, and thus likely to have somewhat
lower costs on a $/bbl basis.
1:28:36 PM
Mr. Kepes looked at slide 40, "CS SB 192 Excluding New Oil
Allowance (Existing Producer)." He explained that the
description of the investment, as discussed, was displayed
in the slide, excluding the new oil allowance. The slide
was attempting to isolate the impact of CS SB 192,
excluding the new oil allowance. He stated that the in the
total government take in the upper right hand corner ranged
from 68 percent to 79 percent. The NPV at $100 per barrel
was approximately $16.7 million.
Mr. Kepes discussed slide 41, "CS SB 192 Including $10 New
Oil Allowance (Existing Producer)." He stated that the
slide followed the same model as slide 40. An existing
producer with 200,000 barrels per day would develop a
100,000 per day working interest project at the same cost.
Mr. Kepes looked at slide 42, "CS SB 192 Excluding New Oil
Allowance (New 100 mb/d Development)." He looked at the
cash flow analysis graph in the upper left hand corner. He
explained that the after tax cash floor in 2009 to 2014 was
negative because of CAPEX pre-production. He stated that
production would be initiated in 2013, and the cash flow
would reach into the positive. He stated that the
investment would represent an NPV of approximately $276
million at 100 per barrel, and an internal rate of return
at 11 percent. He directed the committee's attention to the
table in the upper right hand corner of the slide, and
noted the total government take rising from 69 percent to a
maximum of 81 percent.
1:33:24 PM
Co-Chair Stedman wondered how back-out costs from
production facilities were incorporated. Mr. Kepes deferred
to Mr. Mayer.
Mr. Mayer stated that the costs, without existing
production, would include some additional operating costs
to account for no base production.
Co-Chair Stedman requested more detail regarding the
inclusion of the back out fees that were negotiated with
the existing producers to use facilities, to determine the
overall impact. Mr. Kepes replied that there were some
assumptions included in the OPEX, and deferred to Mr. Mayer
to provide more information. Mr. Mayer furthered that the
included OPEX in new development without base production,
was relatively high.
Mr. Kepes discussed slide 43, "CS SB 192 Including $10 New
Oil Allowance (New 100 mb/d Development)." He explained
that the $10 new oil allowance provided added approximately
$50 million of NPV to a project, and the internal rate of
return was the same. He surmised that the changes provided
by the addition of the $10 new oil allowance, were fairly
modest with respect to the model without the new oil
allowance.
Mr. Kepes looked at slide 44, "Oil/Gas Decoupling":
1. Under ACES, production tax value is assessed on a
combined BTU-equivalent basis for both oil and gas
production.
-So long as no major gas export project is under
development, this has no impact.
-In the event of the development of a major gas export
project, however, when gas prices are significantly
lower than oil prices, this could lead to significant
reductions in Government Take.
2. CSSB 192 includes a provision to de-couple the
calculation of production tax value on North Slope gas
sold out-of-state, in order to eliminate this impact
of gas production.
-The impact of the decreased government take without
decoupling is only pronounced with very low gas
prices, and very large gas production.
-In order to illustrate the impact at the extreme, the
following analysis thus assumes a $1/mcf net-back sale
price for North Slope gas, and a 2018 1bcf/d gas
project. Under less extreme scenarios, the difference
with and without decoupling would be significantly
less.
1:38:46 PM
Co-Chair Stedman remarked that the "major line" would
provide $4.50 bcf per day. Mr. Kepes stated that it was
larger than stated.
Mr. Kepes discussed slide 45, "CSSB 192 - Existing Producer
with 2018 Gas Project, No Decoupling." He looked at the
cash flow analysis graph in the upper left hand section of
the slide, and remarked that in 2014 to 2018 there was a
"dip" in the after-tax cash flow line. The substantial
"dip" represented CAPEX. He furthered that the NPV in that
particular portfolio was equally substantial. He remarked
that the table in the upper right hand corner of the graph
displayed a total government take range from 67 percent to
71 percent.
Mr. Kepes looked at slide 46, "CSSB 192 - Existing Producer
with 2018 Gas Project, Including Decoupling." He remarked
that the government take changed from a peak of 71 percent
with no decoupling to 78 percent including decoupling. He
felt that the impact was relatively modest. He suggested an
analysis be conducted of $4 bcf per day, because it seemed
more realistic.
Co-Chair Stedman felt that cash flow numbers were more
important than government take numbers, because the
government take numbers "hid" the amount of cash that was
moved around. He noted a letter from the Department of
Revenue that stated that combining oil and gas cost the
State $80 million a year with no gas sales.
Mr. Kepes discussed slide 47, "Regime Competitiveness:
Relative Government Take: Average Government Take of Global
Fiscal Regimes at $100/bbl." He stated that the slide
displayed a comparison of different fiscal regimes against
a set of regimes globally. He pointed out that CS SB 192
was generating a government take of approximately 76
percent, and pointed out how that compared to ACES and
other jurisdictions.
1:43:54 PM
Mr. Kepes looked at slide 48, "Regime Competitiveness:
Relative Government Take: Average Government Take of Global
Fiscal Regimes at $140/bbl." He remarked that it was the
same analysis as slide 47, but at $140/bbl. He pointed out
that both ACES and CS SB 192 moved "up the scale somewhat"
relative the other less progressive jurisdictions.
Mr. Kepes discussed slide 49, "Regime Competitiveness:
Relative Government Take: Marginal government Take of
Global Fiscal Regimes at $100/bbl." He stated that the
analysis was conducted with a $1/bbl step at a time, and
looked at the change in government take on that marginal
basis.
Co-Chair Stedman noted a slight improvement. Mr. Kepes
agreed.
Mr. Kepes touched on slide 50, "Regime Competitiveness:
Relative Government Take: Marginal Government Take of
Global Fiscal Regimes at $140/bbl."
Mr. Kepes discussed slide 51, "Conclusions - Changes to
Progressivity, Overall Government Take, and Oil/Gas
Decoupling":
1. CSSB 192 uses two key mechanisms to reduce
government take relative to ACES:
-A reduction in the rate of progressivity that applies
above $30/bbl Production Tax Value (PTV) from a 0.4
percent increase for each one dollar increase in PTV,
to a 0.35 percent increase.
-A reduction in the maximum rate of production tax,
from 75 percent at $342 PTV, to 60 percent at $202
PTV.
2. The impact of the reduction in the progressivity
coefficient on overall levels of government take and
on project economics is limited to around a single
percentage point of government take at $100 ANS crude.
3. The impact of the 60 percent maximum rate for
production tax is more significant, but only at very
high oil prices.
-On a current-year basis, government take under CSSB
192 would be significantly lower than under ACES only
at ANS crude oil prices above $230.
-On a project-lifecycle basis, that threshold may be
lower, as a result of the impact of bracket-creep
(since progressivity thresholds are specified in
nominal terms) - but the impact on project economics
at likely price levels remains negligible.
Mr. Kepes looked at slide 52, "Conclusions - New Oil
Allowance":
1. Even under highly aggressive assumptions regarding
the potential for a new-source development for a given
company, the impact of the $10 allowance for "new oil"
is almost undetectable.
-In the context of both a development by an existing
producer, and a development by a new producer,
Relative Government Take changes only by fractions of
a percentage point, at most.
-For an existing producer, portfolio NPV rises by only
a tenth of a percentage point.
-For a new producer, the impact on project value is
greater, but remains insignificant in the context of a
$10 billion capital development.
2. The major reason for this is because rather than
providing an ongoing allowance for new-source
production, the amendment provides an allowance only
for production that, in a given year, is incremental
to the previous year's production.
-For an existing producer with declining base
production, only a very large development is capable
of producing "new oil" under this development at all.
-Even for a new producer, the value of the allowance
remains highly limited.
3. An allowance which was instead provided for new-
source production could potentially have a greater
impact, however adequately defining such new-source
production could be difficult in practice,
particularly in an environment where most new
production will come from existing areas.
1:49:22 PM
Senator Thomas looked at slide 51, and wondered how many of
the various oil jurisdictions had a combined oil and gas
tax. Mr. Kepes replied that very few jurisdictions had a
combined oil and gas tax. He furthered that most locations
treated gas slightly differently from one another. He
stated that the differential in value, whether calorific or
value-based, had become so large, that a combined oil and
gas tax aggravates the system.
Mr. Kepes introduced the section, "Global Strategy and
Portfolio Overview of Major Alaska Producers." He explained
that the section provided an assessment of the major Alaska
producers' portfolios, priorities, and strategies. He
stated that the data that was used was either public or
from PFC Energy's proprietary databases.
Mr. Kepes discussed slide 55, "BP: Global Areas of Upstream
Operations":
Strategic Signature
-BP is a global integrated company, with production in
16 countries and upstream operations in an additional
10 countries.
-In 2010, total global production averaged
approximately 3,773 mboe/d, making it the second
largest company in the peer group (superseded by
ExxonMobil (approximately 4,450 mboe/d). The Russia
& Central Asia (RCA) and North America regions
accounted for approximately 55 percent of 2010
production.
-BP recorded a 4.5 percent drop in production in 2010
over 2009, reflecting the impact of asset sales, the
post-Macondo slowdown in US GOM deepwater activity,
and continued decline from the company's deepwater and
mature shallow water assets.
-Much of the post-Macondo portfolio rationalization
program (targeting $30 billion in asset sales
including mid/downstream assets) has been completed.
The result is a pared down and more focused geographic
portfolio.
-BP expects growth of 1 percent -2 percent per annum
through 2015. BP's growth strategy is three-pronged
based on Deepwater Basins, Global Gas, and Giant
Oilfield Development. BP's deep water position is
based on operations in the US GOM, Angola, Egypt and
Brazil. The Global Gas position is principally
comprised of US, Trinidad & Tobago, and North Sea.
Giant oil fields are dispersed throughout the global
portfolio. Based on PFC Energy projects, growth is
unlikely before 2015.
-The growth strategy above includes approximately $20
billion net investment commitment to 16 projects
sanctioned over 2010-2011. This is expected to curb
ROCE performance for the coming 2-3 years.
-With the burden of the Macondo oil spill and
reparations continuing through the mid-term, BP will
be hard pressed to outperform its peers on any key
metrics, leaving the company open to calls for more
radical restructuring
He stated that, according to PFC Energy's analysis, BP
considered Alaska a "harvest area."
1:59:56 PM
AT EASE
2:10:02 PM
RECONVENED
2:10:09 PM
Mr. Kepes discussed slide 56, "BP Global Production
Portfolio - 2010":
Russia: BP's largest producing country (963 mboe/d),
representing approximately 26 percent of 2010 output.
Substantial long term growth potential. Continued
interest in Russia (and Arctic) expansion, despite
limitations arising from the TNK-BP joint venture.
Canada: modest conventional production, with future
potential tied to oil sands.
US: 2nd largest producing country, with core deepwater
area. Activity slowed post-Macondo, yet expect strong
future growth. Onshore L48 is key gas area
(approximately 22 percent of 2010 global output), with
focus on unconventionals. Alaska potential tied to
commercialization of Prudhoe Bay resources.
UK: Declining position from mature offshore assets.
High-value operating area, generating large cash
flows.
Trinidad & Tobago: Core gas producing area tied to
Atlantic LNG.
Azerbaijan: Participation in 2 large-scale projects:
Azeri-Chirag-Guneshli & Shah Deniz.
UAE: Core position through equity affiliates, though
concession are being re-negotiated.
India: 2011 Partnership with Reliance for exploration
in shallow and deepwater.
Australia and Indonesia are key gas producing areas
tied to investments in LNG.
Iraq: Development of Rumailia oil field.
Angola: Sole presence in SSA is Angola deepwater.
High growth from 2002-2009, now challenged with start-
up of several unsanctioned projects.
Argentina: onshore & shallow water assets (held by
PAE) were to be sold to Bridas, but transaction failed
in 4Q:11.
He stressed that the analysis was based on PFC Energy's
assessment and opinion. He stated that the slide pointed
out asset type, conventional on-shore, and conventional
shallow.
Mr. Kepes looked at slide 57, "Total Portfolio Evolution:
BP vis-à-vis the Competition":
In 2010, BP was the second largest producer of the
peer group. Yet, from 2010 to 2015, BP and COP are
the only two companies to experience a reduction.
2000-2010: Production increases from approximately
3,080 mboe/d to approximately 3,780 mboe/d due to
addition of Russia (approximately 960 mboe/d),
Trinidad & Tobago (approximately 250 mboe/d) and
Angola (approximately 170 mboe/d). This expansion
offsets declines from Europe (approximately 660 mboe/d
and North America approximately 350 mboe/d).
2011-2015: BP's production is expected to decline from
2000-2015, due mostly to the post-Macondo asset
divestiture program, combined with curbed activity in
the GOM deepwater.
Mr. Kepes discussed slide 58, "Reserves and Production: BP
vis-à-vis the Competition":
2000 - 2003: BP experienced significant reserve growth
(from approximately 15,000 mmboe to approximately
18,000 mmboe) equivalent to approximately 6.5 percent
CAGR. The increase is the result of added reserves in
Africa (Angola), Equity Affiliates (Russia) and Asia-
Pacific. Production grew at a slower pace
(approximately 3 percent CAGR) during this period.
2003 - 2004: The formation of TNK-BP results in an
increase of approximately 600 mboe/d from 2003 to
2004.
2005-2010: Production and reserves remain relatively
unchanged. Reserves remain within the range of 17.4 -
18.0 billion boe. Production remains within the range
of 1,462-1,389 mboe/d.
2:16:07 PM
Mr. Kepes looked at slide 59, "Reserves and Production: BP
Intra-Portfolio Performance":
Roughly 60 percent of production and reserves are
concentrated in the US and Equity Affiliates (mostly
comprised of TNK-BP since 2003).
European production (and reserves) declined rapidly
from 2000-2006 (Area is now reported as UK and Rest of
Europe).
Africa (mostly Angola deepwater) production more than
doubled from 2002 to 2009.
Mr. Kepes discussed slide 60, "How the Portfolio is
Financed: Sources and Uses of Cash":
Over the decade, Africa (mostly Angola deepwater) has
rapidly progressed from an area of investment to an
area generating cash surplus. Africa was BP's second
largest cash generator in 2010.
The US is the leading generator of cash flow this
decade, allowing for re-investment in other areas.
Mr. Kepes looked at slide 61, "Global Production: Evolution
of the Portfolio."
Asia Pacific: Relatively small producing area
(approximately 6 percent of 2010 output). Production
largely from offshore Australia and Indonesia with
lesser volumes from China. Partnership with Reliance
(India) creates exploration opportunities. Focus on
deepwater and CBM. Divested assets in Pakistan and
farmed down in Vietnam.
Europe: Mature and generally declining production
position in the UK and Norway, mostly in shallow
waters. Exploration and development projects are
ongoing, often leveraging BP's existing infrastructure
and assets in the region.
Latin America: Growth driven by shallow water gas
developments in Trinidad & Tobago. Focus on onshore
gas commercialization in Bolivia. Failed to sell
Argentine assets (held through PAE) to Bridas in 2011.
Brazil deepwater offers mid- to long-term potential
from newly acquired deepwater acreage.
Middle East and North Africa: Position built from
collaboration with NOCs (Adma-Opco, GUPCO, Sonatrach,
LNOC, etc.). Substantial new source growth expected
from Iraq, Egypt deepwater, offshore Oman.
Exploration opportunities in Jordan.
North America: Second largest production region &
largest cash flow generator. Deepwater GOM holds
significant growth potential after years of
investment. US L48 portfolio is material, yet
declining, source of gas, with a growing emphasis on
shale gas. Additional future growth from Canadian oil
sands.
Russia and Central Asia: Principally comprised of TNK-
BP venture created in 2003, now BP's largest source of
production, characterized as long-life, slow decline
output. In Azerbaijan, production is from large-scale
ACG and Shah-Deniz. The Region is the largest source
of new source volumes through 2015.
Sub-Saharan Africa: Operates only in the Angola
deepwater play, which quickly emerged as a key oil-
producing country. BP has collaborated with operators
TOTAL (Block 17) and Chevron (Block 15). In the
future, development of BP-operated blocks 31 and 18 is
expected to reverse the recent decline in production.
2:23:51 PM
Co-Chair Hoffman wondered if slide 61 portrayed potential
development, such as the Beaufort and Chukchi conventional
shallow. Mr. Kepes replied that if there was a viable
potential project, it would be included in the analysis. He
furthered that if there was a pure expiration play, without
commercial field development, it would not be included in
the analysis. He added that a project would not be included
if there was a heavy oil or viscous oil project that was
not considered commercial under existing commercial terms.
Co-Chair Stedman requested further detail regarding the
Chuckchi project. Mr. Kepes agreed to provide that
information. He noted the potential in the off-shore
drilling, but felt that it would not be development for a
few years down the line.
Mr. Kepes discussed side 62, "Global Production: Country
Growth Project Analysis":
Russia is a leading source of mid-term new source
volumes. Production (from TNK-BP) include expansions
to existing areas such as Orenburg, and greenfield
developments such as the Uvat and Verkhnechonskoye
fields.
BP's participation in Azerbaijan's ACG Phases 1-4 is
among the largest net new source projects in the BP
portfolio.
Angola deepwater provides large share of new source
oil.
The Asia-Pacific Region (Indonesia, Australia) and the
MENA Region (Egypt, Algeria, and Oman) are the key
providers of new source gas in the medium term.
By 2015, the US represents the largest area for BP, by
number of project. The US holds 11 new source
projects, of which 9 are GOM deepwater and 2 are
onshore Alaska.
BP's new source Canadian oil sands projects are
expected on stream post-2015.
BP's new source portfolio is driven by (1) Deepwater
projects (Angola and US GOM); and (2) Russia (mostly
onshore oil).
The Asia-Pacific remains a mostly gas-production area.
Unconventional (Asia-Pacific and North America) and
oil sands (Canada) projects are largely immaterial
until 2020 or so.
Co-Chair Stedman wondered if there was further information
regarding BP's two onshore sights in Alaska. Mr. Kepes
agreed to provide that information.
2:27:42 PM
Mr. Kepes touched on slide 63, "BP in Alaska." He stated
that BP held North Start, Prudhoe Bay Gas, Liberty, and Pt.
Thomson Gas fields in Alaska.
Mr. Kepes stated that slide 64, "BP Alaska Activity and PFC
Energy Assessment":
ACTIVITY:
Most of BP's assets are located on the North Slope,
where production volumes have generally declined
because of the maturity of the asset base and/or gas
infrastructure constraints. Liquid production has
declined from approximately 224 mboe/d in 2006 to
approximately 166 mboe/d in 2010, while gas production
has fallen from approximately 67 mmcf/d to
approximately 46 mmcf/d over the same period.
BP's largest source of production is the Greater
Prudhoe Area (26 percent w.i., operated), covering
approximately 150,000 acres with more than 1,000
active wells. Gas resources are currently stranded
because of the lack of pipeline capacity to southern
markets. BP and ConocoPhillips had teamed up to
propose a new natural gas pipeline (Denali) to run
from Prudhoe Bay through western Canada to US markets.
However, in May 2011, the partners announced that
plans for the pipeline had been terminated, citing the
lack of long-term purchase contracts. The proposed
pipeline would have accommodated 4 bcf/d of natural
gas.
BP and partners are moving forward with the
development of gas liquids on the approximately 8 tcf
Point Thomson field (32 percent w.i., non-operator).
The gas cycling project is expected to produce
approximately 10 mb/d of liquids; first production is
targeted for 2014. Full field development awaits gas
transport infrastructure.
In the Beaufort Sea, BP has suspended work on the
extended-reach drilling program on the Liberty oil
field (100 percent w.i.), pending revision of project
design and schedule.
BP is also seeking to develop viscous (Kuparuk) and
heavy (Milne) oil resources on the North Slope.
PFC ENERGY ASSESMENT:
Current production volumes are modest and declining,
yet significant potential lies in the long-term
commercialization of Prudhoe Bay and Point Thomson gas
resources. Cancellation of the Denali gas pipeline
proposal leaves BP as a potential supplier to an
alternative pipeline-export option, should one be
approved and developed.
Co-Chair Hoffman looked at slide 63, and wondered where the
project was that was planned for the following summer.
Mr. Kepes stated that there were many wells that were being
drilled, but were not considered official projects.
Co-Chair Hoffman queried Shell's offshore drilling
projects. Mr. Kepes replied that the wells were still
expiration wells, but were still fairly speculative.
Mr. Kepes looked at slide 65, "PFC-Identified Challenges":
1. Re-establish its operator profile in the global
deepwater: While its competitors extend their
commitments to global LNG, unconventional shale gas
exploitation, and oil sands development in order to
drive future portfolio growth, BP has deepened its
commitment to the global deepwater play, despite the
ongoing fallout from the Macondo oil spill. Expansion
of its US GOM lease holdings (through the Devon
portfolio acquisition), entry into the Brazil
deepwater, and a material commitment to the K-G Basin
deepwater play in India, together with phased field
development offshore Angola and West Nile Delta in
Egypt, positions BP as arguably the premier deepwater
player in the Global Player peer group. BP will be
under the spotlight regarding its future conduct and
performance throughout the global deepwater basins.
2. Resolve shareholder relationship issues within the
TNK-BP JV: Accounting for approximately 26 percent of
total worldwide production in 2010 (and approximately
36 percent of total worldwide oil production), the
TNK-BP position is absolutely core to the BP portfolio
from a volumetric perspective. However, the
unsuccessful attempt to partner with Rosneft in the
Russia Arctic raises concern over how much value TNK-
BP can continue to create for BP. With TNK-BP now
focused on international expansion, must BP settle for
lower returns from what has until now been a highly
lucrative position?
3. Complete the portfolio rationalization process: The
strength of the global asset transactions market
prompted BP to expand its divestiture program from an
initial $20 billion to $30 billion, divesting large
swaths of its portfolio deemed non-Core and/or non-
aligned with the company's growth focus. While the
company did not plan on the depth of portfolio
rationalization undertaken to date, this is a rare
opportunity to high-grade asset holdings with the
blessing of shareholders and analysts alike. BP is
expecting to complete the divestiture process by end-
2011.
4. Determine a path forward in the Brazil deepwater:
Having secured Brazil government approval to acquire
the Devon asset portfolio, BP has established a
foothold in the Brazil deepwater, with potentially the
largest operated pre-salt portfolio outside Petrobras.
The next step is to determine the appropriate approach
to growth in the pre-salt play. With legislation now
in place granting NOC Petrobras a minimum 30 percent
w.i. and operatorship in all unlicensed pre-salt
acreage, this may be another case of executing a
strategic alliance (similar to that secured with
Reliance in India and proposed with Rosneft in the
Russia Arctic).
5. Accelerate development of US Onshore unconventional
gas resource: BP received a very competitive price for
the Permian Basin and Western Canada conventional gas
assets sold to Apache (totaling approximately 75
mboe/d of production and approximately 340 mmboe of
reserves, equivalent to approximately $24.60/boe of
reserves in the ground or approximately
$109,000/flowing boe of production). This is
particularly so given what is shaping up to be an
extended period of gas price weakness in the North
America market. To make up for lost volumes, BP may
look to accelerate production from its approximately
10 tcf of reserves in the Woodford, Fayetteville,
Haynesville, and Eagle Ford shale gas plays.
6. Accelerate development of BP's oil sands leases:
BP has built up a material oil sands lease portfolio
in Western Canada, including 50 percent w.i. in the
Sunrise in situ development project (sanctioned in
November 2010), a 75 percent w.i. in the Terre de
Grace in situ project (secured in March 2010 from
Value Creation for approximately $900 million), and 50
percent w.i. in the Kirby in situ oil sands leases
(with the other 50 percent divested to Devon in March
2010). Full development of these projects could
represent 500-600 mbo/d of stable, long-life oil
production, complementing the "Giant Oil Fields"
growth platform and providing a portfolio buffer
against the steep decline production profiles
associated with deepwater developments.
2:33:53 PM
Mr. Kepes discussed slide 66, "ConocoPhillips: Company
Overview":
Strategic Signature
Following two years of corporate net income losses,
steep decline in its share price, and a persistently
high debt-to-capital ratio, in March 2010
ConocoPhillips announced a new strategic pathway,
directing proceeds from an approximately $15 billion
asset and joint venture divestment program to reduce
its debt-to-capital position, increase near-term
shareholder returns, shift further out of the
downstream, and position the company for future growth
from a smaller but higher-value portfolio position.
Since the announcement of the 2010-2012 Restructuring
Plan, ConocoPhillips has executed on approximately $7
billion in asset sales, divested its entire 20 percent
equity interest in LUKOIL, and directed proceeds from
these sales to debt reduction and share repurchase. In
July 2011, ConocoPhillips announced the next step in
its restructuring: the creation of two separate
corporate entities, Downstream and a pure play, E&P.
With production in 15 countries and upstream
operations in an additional 7 countries,
ConocoPhillips' most recent guidance suggests
production reaching a low of approximately 1.5 mmboe/d
in 2012, recovering to 1.64-1.69 mmboe/d by 2015. The
company will rely on a large, diversified upstream
portfolio positioned heavily in OECD countries (namely
the US, Canada, Australia, UK, and Norway, which
accounted for approximately 72 percent of worldwide
production in 2010).
Growth of 0.5 percent per annum from 2012 through 2015
is forecast to come from Global Gas/LNG, SAGD Oil
Sands, and Unconventional developments. However, as
ConocoPhillips now stands to compete with the
Independent, non-integrated oil & gas companies, the
company's future strategy remains uncertain.
Mr. Kepes discussed slide 67, "ConocoPhilips: Global Areas
of Upstream Operations." He felt that Alaska should be
considered a "core area" for ConocoPhilips. He explained
that ConocoPhillips had several areas of activity in
Alaska: expiration activity off-shore, Cook Inlet, and
North Slope. He opined that the North Slope would be
considered a harvest area for ConocoPhilips.
Mr. Kepes looked at slide 68, "ConocoPhilips Global
Production Portfolio - 2010":
Russia: LUKOIL sale leaves ConocoPhillips with modest
production from its two joint ventures in Russia
(Polar Lights Company and Naryanmarneftegaz). Regional
production is forecast to drop from 21 percent of'
worldwide production in 2009 to a projected 3 percent
in 2011.
Canada: Among the largest natural gas producers in
Canada. Three SAGD oil sands developments-Christina
Lake, Foster Creek, and Surmont-have added long-life
production volumes to ConocoPhillips' portfolio.
US: Largest producing country, with core L48
production where liquid-rich areas (Eagle Ford) will
be prioritized over gas assets. Declining mature
assets in Alaska could be offset by prospective
deepwater volumes in long-term.
UK and Norway: Region characterized by mature,
declining assets; satellite projects planned to offset
regional base declines.
China: Modest offshore production from Bohai Bay.
Qatar: Qatargas 3 (onstream in 2010) is key driver to
regional gas growth.
Nigeria: Interests in six onshore assets, serving as
feedstock to Nigeria LNG Trains 4-6.
Australia: APLNG Phase 1 sanctioned in 2011; longer-
term upside in Australia could stem from assets in the
Browse Basin or Timor Sea (e.g. Greater Sunrise).
Vietnam: Continued development of mature Cuu Long
Basin; potential divestment target.
Malaysia: Development of deepwater fields (Gumusut-
Kakap and Kebabangan) will bring Malaysia into
ConocoPhillips' producing country portfolio.
Indonesia: Largest contributor to Asia-Pacific
production; ongoing development of Corridor PSC and
South Natuna Block B.
Libya: Legacy onshore Waha concession; above ground
conflict will delay new source oil projects.
Algeria: Onshore oil field production; additional
volumes from El Merk (EMK) expected for 2012 start-up.
2:37:57 PM
Mr. Kepes discussed slide 69, "Total Portfolio Evolution:
ConocoPhilips vis-à-vis the Competition":
ConocoPhillips' 2010-2012 Restructuring Plan will see
the company become the largest of the Independent,
non-integrated international oil & gas companies,
compared to its former position as the third-smallest
of PFC Energy's expanded Global Player peer group.
2000-2010: Production increases largely driven by the
merger of Conoco and Phillips in the beginning of the
decade (growing volumes from 698 mboe/d in 2000 to
1,082 mboe/d in 2002) and the Burlington Resources
purchase in 2006 (growing volumes from 1,824 mboe/d in
2005 to 2,358 mboe/d in 2006). The gradual acquisition
of a 20 percent stake in LUKOIL was a key driver to
mid-decade growth.
2011-2015: ConocoPhillips's production is expected to
decline from 2010-2015, due to the company's intensive
asset divestiture program (the initial approximately
$15 billion asset and joint venture divestment
program was expanded in 2011 when ConocoPhillips
announced it would shed an additional $5 billion -$10
billion in non-Core assets by end-2012). Volumes are
forecast to decline from approximately 2,078 mboe/d in
2010 to approximately 1,674 mboe/d in 2015.
Mr. Kepes looked at slide 70, "Reserves and Production:
ConocoPhilips vis-à-vis the Competition":
2000-2006: Production and reserves grow steadily,
largely a result of acquisition: from 271 mboe/d and
5,019 mmboe in 2000 to 682 mboe/d and 11,469 mmboe in
2006. R/P ratio declines from approximately 18 to
approximately 13 years.
2006-2010: Both production and reserves experience a
reversal in growth; however reserves fall more
steeply. By 2010, production was 776 mboe/d and
reserves decreased to 8,310 mmboe, resulting in the
lowest R/P ratio recorded in the decade at
approximately 11 years. In 2010, declines in
production were primarily due to field decline, the
impact of higher prices on production sharing
arrangements, and the sale of Syncrude.
Mr. Kepes discussed slide 73, "Global Production: Evolution
of the Portfolio":
Asia Pacific: Project queue 14 projects deep makes
Asia-Pacific the largest development pipeline in all
of ConocoPhillips' portfolio. Region estimated to
occupy 20 percent of 2011 upstream CAPEX. New projects
in both legacy countries (Indonesia, Vietnam) are
being complimented by startups in Malaysia (Gumusut-
Kekap, Kebabangan) and Australia (APLNG).
Europe: Mature and generally declining production
position in the UK and Norway, mostly in shallow
waters. Satellite projects poised to somewhat offset
base declines.
Latin America: After reaching historic peak production
in 2005, volumes fell to zero in 2009. The Latin
America portfolio, largely acquired through the
Burlington transaction, has never been a material part
of ConocoPhillips' global operations. With no new
volumes anticipated in the portfolio, a complete exit
from the region could be likely.
Middle East and North Africa: Future growth is largely
tied to the Qatargas 3 LNG project and El Merk (EMK)
in Algeria. Longer-term growth is poised to stem from
Libya (as yet unsanctioned joint NC 98 and North Gialo
developments) assuming a timely re-commencement of
upstream activities.
North America: Largest production region and cash flow
generator. New growth initiatives focus on
exploitation of Eagle Ford shale liquids and Canadian
oil sands (Christina Lake, Foster Creek, and Surmont),
which are projected to reverse the decline in Canadian
production by 2014 and deliver medium- and long-term
volume growth.
Russia and Central Asia: LUKOIL sale leaves
ConocoPhillips with only modest production from its
two joint ventures in Russia and few growth
opportunities within the remaining portfolio. The sole
growth asset is an 8.4 percent stake in the Kashagan
field, which continues to face major challenges.
Sub-Saharan Africa: Onshore assets serve as feedstock
to Nigeria LNG Trains 4-6. Longer-term upside tied to
feedstock for the yet-to-be-sanctioned Brass LNG
plant, while 2011 re-positioning in Angola could
provide exploration opportunities critical to securing
new source ventures for long-term growth.
Mr. Kepes looked at slide 74, "Global Production: Country
Growth Project Analysis":
ConocoPhillips's new source portfolio is driven by (1)
Shallow water gas production (Qatar); (2) Canadian
SAGD Oil Sands Developments; and (3) US Unconventional
production (Eagle Ford).
Deepwater projects sourced mainly from the Asia-
Pacific region (Malaysia) and the US GOM deepwater
(mostly non-operated positions), will ramp up steadily
over the decade; by 2020 deepwater is poised to
represent 7 percent of global volumes (compared to
approximately 2 percent in 2010).
2:42:04 PM
Mr. Kepes looked at slide 79, "PFC-Identified Challenges":
Competing as a "Pure Play" E&P Company: The separation
of ConocoPhillips into two, stand-alone Upstream and
Downstream entities is scheduled to be finalized in
1H: 2012. The approximately 85 percent of total
portfolio value residing in E&P assets will thereby
become the largest "pure play" E&P Independent, a
competitor landscape position the company held
uncomfortably prior to the Burlington Resources
acquisition in 2006. Can ConocoPhillips Upstream
compete successfully in the Independent's space by
delivering either leading shareholder returns or
leading production growth? Or has it simply re-
established its original dilemma-too large to compete
with the faster moving International Independents, and
too small to compete with the Global Players? And if
so, does it survive?
Re-Establishing a Value Proposition: ConocoPhillips'
new strategic focus on Sustained Value Generation is
intended to re-establish the company's competitive
advantage in the E&P space. In the near-term, the
2010-2013 Restructuring Plan will deliver a smaller
company with limited medium-term production growth and
improved, but unlikely to be leading, ROCE and
financial performance. Clearly, the cannibalization of
the company's assets and recycling of proceeds to
shareholders in order to shore up share valuation and
total shareholder returns is a stop-gap strategy at
best. Given continuing financial and operational
challenges (ROCE, production cost, upstream net
income, etc.), ConocoPhillips may struggle to deliver
a value proposition that will compete successfully in
either the Global Player or International Independents
peer group.
Improving Operational Performance: While showing
improvement in finding and development costs,
ConocoPhillips ranks at or near the bottom of the
expanded Global Players peer group in net income/boe,
production costs/boe, and Upstream ROCE. The current
portfolio high-grading has already delivered Upstream
ROCE improvement (from 7 percent in 2009 to 10 percent
in 2010) and should deliver improvement in operational
metrics; both Syncrude and the LUKOIL holdings were
arguably underperforming positions. With long lead
time, large scale, capital intensive developments like
Qatargas 3, Jasmine, Kashagan Phase 1, and Surmont
poised to deliver material production and cash flow,
ConocoPhillips should see the flow-through benefits in
terms of more competitive ROCE and operational
metrics.
Delivering Production Growth: The share repurchase
program accompanying portfolio rationalization under
the Restructuring Plan is projected to deliver
approximately 3 percent growth in per share production
in 2010 and 2011. However, physical volumes will
decline in absolute terms over the 2010-2011 period-by
approximately 208 mboe/d in 2010 from 2009 levels and
a further approximately 360 mboe/d in 2011 from 2010.
The only region poised to deliver higher production
volumes in 2020 versus 2010 is the relatively minor
MENA region, projected to reach approximately 177
mboe/d in 2020 versus 72 mboe/d in 2010. New source
volumes in Canada and the North Sea will struggle to
offset mature asset declines, delivering flat
production in the core North America and Europe
regions, while the LUKOIL sell-down will dampen what
was once considered a core driver of future growth for
the company. While boasting a 10 billion boe resource
base, it is not clear how ConocoPhillips will deliver
the promised surge in organic growth over the 2015-
2020 period from its captured portfolio-although the
enhanced CAPEX spend in the Eagle Ford play is a good
starting point. Barring a material acquisition
(certainly not out of the question), the company will
be looking to its exploration portfolio to deliver a
medium term "engine of growth".
Mr. Kepes discussed slide 80, "ExxonMobil: Company
Overview":
ExxonMobil is the largest global integrated company
(volumes averaged approximately 4,450 mboe/d in 2010),
with production in 21 countries and upstream
operations in an additional 20 countries.
ExxonMobil has long adhered to a growth strategy based
on scale, basin dominance, and execution excellence,
which has required the company to seek continuous
access to investment opportunities of adequate size
and materiality.
In 2010, faced with the commissioning of the final
elements of the company's Qatar project portfolio (the
final four approved LNG trains at RasGas and Qatargas,
and Phase 2 of the Al Khaleej gas project), declining
production in Europe and Asia-Pacific, and already
holding a considerable stake in the Canadian oil
sands, ExxonMobil took an aggressive move into
unconventional shale gas exploitation.
The 2009 acquisition of XTO Energy brings materiality
to ExxonMobil's technical expertise in tight gas, CBM,
and shale oil and gas exploitation, with approximately
2.3 bcf/d and 87 mboe/d of production, proved reserves
of approximately 2.3 billion boe, and a resource base
of 7.5 billion boe. From a position of basin
dominance in the US Onshore, ExxonMobil will seek to
build a global unconventional portfolio; as such, the
company has already begun purchasing prospective
acreage in Argentina, Germany, Poland, Indonesia, and,
most recently, China.
Largely a result of the acquisition, ExxonMobil
recorded a 13 percent increase in production in 2010
over 2009. The company will seek growth of 4-5 percent
per annum over the 2009-2014 period.
Mr. Kepes looked at slide 81, "ExxonMobil: Global Areas of
Upstream Operations." He explained that PFC Energy analyzes
each company's portfolio to look at the growth prospects,
decline rates, amount of re-investments, and materiality.
He remarked that 50,000 barrels per day to a company that
produces 4.4 million barrels per day was much different
than 50,000 barrels a day to a company that produces
200,000 barrels per day. He stressed that relative
materiality must be factored into the analysis. He stated
that Qatar was the largest single country contribution to
the United States as of 2011. In 2011, ExxonMobil bought a
large shale gas company, XTO, which made the United States
the largest single country producer again. He noted that it
was remarkable for Qatar to contribute so much, because the
country was so small. He added that Alaska was a "harvest
area" for ExxonMobil.
Mr. Kepes discussed slide 82, "ExxonMobil Global Production
Portfolio - 2010":
UK and Norway: Mature North Sea assets have delivered
volume declines of approximately 5 percent per annum
in Europe over the last 5 years.
Russia: Strong performance track record at Sakhalin I
and Arkutun-Dagi. Rosneft Strategic partnership could
be a dial-turner in Russia (Arctic exploration & tight
oil resource exploitation).
Kazakhstan: Participation in 2 large-scale projects:
Tengiz & Kashagan.
Canada: Oil sands volumes (Cold Lake, Syncrude, and
Kearl projects) will dominate out-year production
growth.
Germany: Legacy gas assets; recent unconventional
acreage acquisition.
US: Largest producing country; regional decade-long
decline reversed with purchase of XTO. XTO combined
with three additional unconventional acquisitions will
make the Onshore L48 the cornerstone of future growth.
Qatar: Represented approximately 20 percent of 2010
output. Decade-long double digit growth driven by
final tranche of sanctioned LNG capacity in Qatar.
Nigeria: Generally declining shallow- and deep-water
assets.
Australia: Gas oriented region, with growth stemming
from Gorgon LNG project and Gippsland Basin shallow
water projects (Kipper and Turrum).
Indonesia: Near-term gas volumes will hold production
steady as ExxonMobil positions for new ventures in the
unconventional space (coal bed methane).
Malaysia: Key gas producing area; focus on enhanced
oil recovery (EOR) and field life extension schemes.
Argentina: legacy, declining gas assets; recent
acreage positioning in prospective shale Neuquen
Basin.
Angola: Multi-field new source developments (Kizomba
Satellites Phase 1, Pazflor, and CLOV) drive regional
growth.
Papua New Guinea: Formerly small contributor to the
ExxonMobil portfolio, PNG will rise in prominence
within the portfolio through the monetization of gas
reserves at PLNG.
2:47:13 PM
Mr. Kepes looked at slide 83, "Total Portfolio Evolution:
ExxonMobil vis-à-vis the Competition." He pointed out that
ExxonMobil was not designed to "grow", because there focus
was on the financial efficiency and return. He stressed
that ExxonMobil would not pursue an investment opportunity
for growth purposes.
Averaging approximately 4.45 mmboe/d in 2010,
ExxonMobil continues to lead its peer group in terms
of production.
2000-2010: For much of the last decade, production
oscillated, rising between 2000 and 2002 and then
again 2005-2007; however, by 2009 production volumes
were only slightly above levels recorded at the start
of the decade, averaging approximately 3.92 mmboe/d.
In 2010, ExxonMobil secured production growth of
approximately 13 percent (approximately 6 percent
excluding the XTO acquisition), reaching approximately
4.45 mmboe/d. For a company that has prided itself on
organic reserves and production growth, the XTO
acquisition marks a considerable departure in growth
strategy for ExxonMobil.
2011-2015: ExxonMobil's production is forecast to grow
modestly between 2010 and 2015, reaching only
approximately 4.54 mmboe/d in 2015. While PFC Energy
estimates are lower than ExxonMobil targets, the
absence of guidance regarding growth projects
associated with the XTO portfolio make the pace of
future growth uncertain.
Mr. Kepes discussed slide 84, "Reserves and Production:
ExxonMobil vis-à-vis the Competition":
ExxonMobil has recorded one of the most consistent R/P
ratios of all of the Global Majors. A slight increase
over the past decade (from approximately 13 years in
2000 to approximately 15 years in 2010) reflects the
increase of reserves in the context of generally flat
line production.
2:50:08 PM
Mr. Kepes looked at slide 87, "Global Production: Evolution
of the Portfolio":
Europe's dwindling R/P ratio is largely due to the
maturity of the asset base.
A focus on exploitation (as compared to exploration)
in Africa has resulted in a decline in the region's
R/P ratio.
Largely due to the XTO acquisition, both reserves and
production experienced a large bump in 2010; in turn,
the US R/P ratio grew from approximately 17 years to
approximately 21 years.
In 2009, ExxonMobil began reporting Bitumen and
Syncrude as distinct reporting regions, which, in
turn, resulted in a sharp decrease in oil reserves and
production reported under the Canada/South America
reporting region.
Mr. Kepes discussed slide 88, "Global Production: Country
Growth Project Analysis":
ExxonMobil's US new source portfolio will dwarf new
source production from all other countries. Through
2015, the US will contribute nearly 40 percent of
global new source incremental volumes, 99 percent of
which will stem from the company's unconventional
activities (acquisitions plus the Piceance tight gas
development).
Production from Qatar will primarily be tied to
development of the North Field and the Qatargas and
RasGas LNG projects, while the rest of the new source
landscape reflects ExxonMobil's expansive upstream
portfolio.
International unconventional developments are likely
to be largely immaterial until 2020 or thereafter
Mr. Kepes looked at slide 90, "ExxonMobil Alaska Activity
and PFC Energy Assessment":
ACTIVITY:
In Alaska, ExxonMobil holds interests in the Greater
Prudhoe, Greater Point McIntyre, and Greater Kuparuk
areas. The company is one of the largest North Slope
producers, although production from the region is
declining; 2010 net production averaged 117 mb/d of
liquids.
Development activities continued at Point Thomson in
2010 (35 percent w.i., operated), and first production
of gas liquids is anticipated in 2014. The longer-term
potential lies in commercialization of the gas
reserves, which is dependent on building a gas
pipeline.
PFC ENERGY ASSESSMENT:
Material harvest position. As the largest holder of
discovered gas resources on the North Slope and a co-
operator of the Prudhoe Bay Western Region
development, ExxonMobil holds a leading position in
Alaska.
2:54:56 PM
Mr. Kepes discussed slide 91, "PFC-Identified Challenges":
Deliver on unconventional resource positioning: The
XTO Energy acquisition and subsequent shale gas
acreage transactions have made ExxonMobil a force in
the North America unconventional resource play. That
said, the company has provided limited guidance on
pace of forward development despite continued acreage
accumulation. Furthermore, given the weak US gas
price environment, it is unclear how rapidly
ExxonMobil's management will grow sales volumes.
ExxonMobil is counting on additional long-term value
arising from the XTO transaction through development
of its expanding portfolio of International
unconventional resource holdings.
Execute on Asia-Pacific LNG Projects: ExxonMobil has
a queue of LNG developments in Asia-Pacific, including
Gorgon LNG (operated by Chevron), PNG LNG, and the
potential Scarborough gas field development, all of
which are poised to generate longer-term volume
growth. Each of these projects comes with significant
technical challenges-CO2 capture and disposal at
Gorgon LNG, remote gas field development and long
distance pipeline transport in the case of PNG LNG,
and the remote offshore location of the Scarborough
field in the Carnarvon Basin (which may result in the
field being dedicated as feedstock supply to the Pluto
or Wheatstone LNG projects, rather than a greenfield
LNG development). Performance will be critical to
ensuring long-term regional portfolio growth.
Maintain leadership in share buy-back and dividend
performance: ExxonMobil has been a clear peer group
leader in returns to shareholders, distributing
approximately $19.7 billion through dividends and
share buy-backs in 2010 and spending approximately
$114 billion on share repurchase over the 2006-2010
period. With the increased emphasis being placed on
unconventional gas resources to deliver future volume
growth, shareholders will be looking for ExxonMobil to
continue its leading dividend and share buy-back
performance, as the core differentiator from its
faster growing (in volumetric terms) peer group
companies.
Replace volume growth from Qatar North Field
commercialization: With full ramp-up of the final
four liquefaction trains at the RasGas and Qatargas
LNG complexes, and continued imposition of a
development moratorium for the North Field resource by
the Qatar government, ExxonMobil will be challenged to
deliver material global growth.
-It is not clear how aggressively ExxonMobil will look
to develop its US Onshore unconventional gas
resources, given current and projected gas pricing in
the North America market;
-Monetization of captured frontier gas resources in
North America (Alaska North Slope, Mackenzie Delta)
continues to face delays in the form of regulatory
hurdles (recently removed for the Mackenzie Valley gas
pipeline project) and gas market supply-demand
balances;
-Development of captured oil reserves in the Caspian
region have experienced significant delays and cost
over-runs, and are coming under increased political
risk through accelerating resource nationalism;
-ExxonMobil was successful in securing a growth
position in Iraq through the West Qurna-1
redevelopment project, but will have to share the
larger Iraqi resource prize with a number of IOCs and
NOCs. It is not clear that Iraq can become a Core
growth area for the company.
SB 192 was HEARD and HELD in committee for further
consideration.
Co-Chair Stedman discussed the following day's agenda.
ADJOURNMENT
2:57:35 PM
The meeting was adjourned at 2:57 PM.
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