02/06/2013 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Presentation: the Alberta Experience | |
| Presentation: Pfc Energy | |
| SB26 | |
| Adjourn |
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
| + | TELECONFERENCED | ||
| + | TELECONFERENCED | ||
| += | SB 26 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
February 6, 2013
3:30 p.m.
MEMBERS PRESENT
Senator Cathy Giessel, Chair
Senator Fred Dyson, Vice Chair
Senator Peter Micciche
Senator Lesil McGuire
Senator Anna Fairclough
Senator Hollis French
MEMBERS ABSENT
Senator Click Bishop
COMMITTEE CALENDAR
PRESENTATION: THE ALBERTA EXPERIENCE
- HEARD
PRESENTATION: PFC ENERGY
- HEARD
SENATE BILL NO. 26
"An Act relating to the Alaska Land Act, including certain
authorizations, contracts, leases, permits, or other disposals
of state land, resources, property, or interests; relating to
authorization for the use of state land by general permit;
relating to exchange of state land; relating to procedures for
certain administrative appeals and requests for reconsideration
to the commissioner of natural resources; relating to the Alaska
Water Use Act; and providing for an effective date."
- HEARD & HELD
PREVIOUS COMMITTEE ACTION
BILL: SB 26
SHORT TITLE: LAND DISPOSALS/EXCHANGES; WATER RIGHTS
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
01/18/13 (S) READ THE FIRST TIME - REFERRALS
01/18/13 (S) RES, FIN
02/02/13 (S) RES AT 10:30 AM BUTROVICH 205
02/02/13 (S) Heard & Held
02/02/13 (S) MINUTE(RES)
02/04/13 (S) RES AT 3:30 PM BUTROVICH 205
02/04/13 (S) Heard & Held
02/04/13 (S) MINUTE(RES)
02/06/13 (S) RES AT 3:30 PM BUTROVICH 205
WITNESS REGISTER
MEL KNIGHT, representing himself
(former) Minister for Resource Development
Alberta, Canada
POSITION STATEMENT: Related how Alberta's fiscal decisions
impacted the energy industries' investment there.
TONY REINSCH, Senior Director
Upstream Group
PFC Energy
POSITION STATEMENT: Provided PFC Energy review of capital
allocation and portfolios of global oil and gas companies.
ANDY ROGERS, Deputy Director
Alaska State Chamber of Commerce
Juneau, AK
POSITION STATEMENT: Supported SB 26.
LISA WEISSLER, representing herself
Juneau, AK
POSITION STATEMENT:
JAMES SULLIVAN, Legislative Organizer
Southeast Alaska Conservation Council (SEACC)
Juneau, AK
POSITION STATEMENT: Opposed SB 26.
HAL SHEPHERD
Center for Water Advocacy and
Norton Bay Intertribal Watershed Council and
Native Village of Elim
Seward, AK
POSITION STATEMENT: Testified in opposition to SB 26.
RICK ROGERS, Executive Director
Resource Development Council (RDC)
Anchorage, AK
POSITION STATEMENT: Testified in support of SB 26.
ACTION NARRATIVE
3:30:07 PM
CHAIR CATHY GIESSEL called the Senate Resources Standing
Committee meeting to order at 3:30 p.m. Present at the call to
order were Senators Fairclough, Dyson, French, Micciche, McGuire
and Chair Giessel.
^Presentation: The Alberta Experience
Presentation: The Alberta Experience
3:30:47 PM
CHAIR GIESSEL announced the first order of business to be a
presentation on how Alberta modified its oil and tax scheme.
3:31:40 PM
MEL KNIGHT, representing himself, former Minister for Resource
Development, Alberta, Canada, said he wanted them to know how
Alberta's fiscal decisions impacted the energy industries'
investment there. In 2004/5, he said industry in Alberta was
relatively robust with an average number of wells drilled per
year and things were going along not too badly, but a political
situation arose around a 1 percent royalty.
He explained that the energy industry has about three pieces to
it and that the oil sands industry, a separate industry from
conventional oil and gas, took a lot of R&D to get going and it
is still managed separately from the rest. Conventional and
unconventional oil and gas operations had been going on for
about 60 years and some heavy oil was between bitumen and
conventionals and is also treated a bit differently in Alberta.
So, the 1 percent royalty became a very hotly contested
political lightning rod, Mr. Knight explained, because opponents
to development of the oil sands and, to some degree, the media
felt it was an issue and it began to be portrayed as the
government of Alberta selling off Alberta's future resources for
a penny on the dollar. In 2006, Alberta's leadership changed and
Mr. Stelmach, from the progressive conservative party, came into
power. He determined that a royalty review was needed and while
it was done because of the oil sands, instead of containing it
to that piece of business, the review went "carte blanche across
the board," and all the structures in Alberta were reviewed at
the same time. The Department of Finance conducted the review,
which lead to some interesting circumstances relative to the
information and the understanding of how the energy industry
performs other than the straight economics of the thing.
3:37:23 PM
Subsequently, a royalty structure was put in place that can
historically be seen as having been a bit of an issue relative
to industry investment in the province, because drilling
decreased immediately. The energy players at the time were very
dissatisfied with what had happened and felt that their net
present value of projects going forward in the province was not
going to leave them in a desirable situation. Now that Alberta
government people understand more about the energy industry,
they know that it moves its money wherever they can get the best
return for their shareholders.
Unfortunately, Mr. Knight said, the global recession contributed
even more to the decline. So, from 2007 through 2009 Alberta
restructured its royalty and worked through various incentive
programs that increased activity dramatically starting in 2009.
As they were taking "a bit of a licking" from places like North
Dakota and British Columbia, they targeted incenting new
technologies that hadn't been applied in Alberta yet.
3:41:54 PM
A new 5 percent royalty rate for horizontal gas and oil drilling
for one year and up to 36 months of production was put into
place; the same for coal bed methane and shale gas. But what
established the upward ramp in drilling activity in 2009/10 was
a two-year drilling royalty credit from meter-age drilled on new
wells or reentries with new formation targets. Anybody that was
working with production in the Province of Alberta could apply
and get credit for royalties owed to the Crown by hiring a rig
and starting new drilling. They also brought in a natural gas
deep drilling program looking for tight sands and shale beyond
2,000 meters (where information was lacking). That 5 percent
royalty started out as a short term program for any new well,
but it was subsequently established as part of the ongoing
Alberta royalty structure.
3:44:46 PM
They have a progressive system that is capped. Prior to the
2010/11 adjustments the cap was at 50 percent, but it got
lowered to 40 percent, which made a big difference to industry
that was working on the new resources.
In his opinion, Mr. Knight said, they need to look at this thing
from a pretty long term horizon, but politicians tend to look
from term to term. Alberta did a 30-year energy policy strategy
all related to horizons that are out at least two decades and,
in some cases, three.
SENATOR DYSON said he may be using the term "royalty"
differently. For Alaska, royalty is part of the contract, he
explained, and pretty standard at 12.5 percent, but Alberta's
varies. Alaska has a severance tax on profits, and he asked how
Alberta's system related to our system.
MR. KNIGHT said he didn't know how it would relate to Alaska's
system and that Alberta doesn't have a severance tax at all. It
relies on industry activity and feels that 60 percent is a fair
receipt for having their resource developed by any individual or
corporation. Alberta looks at this issue from three points of
view: as the owner of the resource and getting a fair return,
which doesn't mean just collecting royalties, and the
development itself, which generates a tremendous amount of
ancillary economic activity. Bonus bid activities went up to
record highs, a couple billion dollars-plus in some years, with
the change.
SENATOR DYSON asked if companies pay local property taxes or
federal taxes and if that was included on his graph.
MR. KNIGHT replied yes they do, but it would be on top of what
the state collects as depicted on the graph. Oil profit gets
taxed provincially and federally and each municipality has a
linear tax structure (not shown) on all the facilities including
pipelines and any other infrastructure they have in place.
SENATOR DYSON asked if he meant the maximum for all taxes should
be 60 percent.
3:51:06 PM
MR. KNIGHT said all the taxes are included in the cost of doing
business. Royalty at the end of the day is the margin.
SENATOR FRENCH asked if their royalty system is based on the
gross value of the oil coming out of the ground.
MR. KNIGHT replied yes; the revenue that someone would earn
selling the resource becomes the focal point of the taxation,
but they are allowed to credit the cost of getting there in the
first place.
SENATOR FRENCH said he read a document called "Royalties in
Alberta" to prepare for the meeting and it said that each oil
well is unique, producing different grades and types of oil as
well as different quantities. Consequently, the amount of
royalties is calculated on each individual oil well and based on
the volume of oil produced from the well, the density of the oil
from the well, the well classification based on the vintage of
when the oil was discovered and a royalty rate factor, and he
asked if that system is still in place.
MR. KNIGHT replied yes.
SENATOR FRENCH asked what has been the economic impact on the
finances of the Alberta provincial government since the 2010
changes were made.
MR. KNIGHT replied they don't know, because the benefits won't
be seen until past 2015, mostly because of low royalty rates on
a lot of the new work. Initially, a tremendous number of people
went to work in Alberta, but the real benefit is to the longer
horizon.
He said that companies need access to capital, the ground and
markets, and Alberta is a bit constrained with respect to access
to market, so some of the work that has been recently won't make
it to the market place for a period of time. In about 10 years'
time, they have attracted 600,000 new Albertans.
3:54:53 PM
SENATOR FRENCH commented that McClain's, a Canadian news
service, reported that Alberta has a $6 billion budget shortfall
and asked if that was accurate.
MR. KNIGHT replied that was a good guess. He explained that most
of the pre-budget work done for Alberta was predicated on them
being able to deliver and sell certain amounts of oil at certain
prices. Constrained access has led to a huge differential
between the price of Western Canada Select and West Texas
Intermediate (WTI) on the shipments going out of Alberta and
that has caused the revenue shortfall, which he didn't think
would be that dramatic. The government might have to withdraw
money from a sustainability fund that they put money into
knowing that things wouldn't be rosy forever.
3:56:38 PM
SENATOR MCGUIRE asked him to describe the competitiveness review
process Alberta established. How did he formulate that committee
and what did they do to become competitive again?
MR. KNIGHT said the situation they faced was quite dramatic. The
people who did the review had not done a lot of in-depth work
with the industry. There was a bit of a misunderstanding by the
people who built the review in the first place of what the
industry needed in order to stay robust in the province. They
put the review in place, made a number of changes in royalty
that were suggested in the review all the while in close contact
with industry players.
3:59:30 PM
He explained that Alberta's situation is slightly different from
Alaska's. Alberta has 20 or 30 large players and 1,200 or 1,500
small players. Through discussions with finance people in the
companies of the majors and the junior players, it became quite
evident that Alberta put itself in a situation where while the
energy industry could make money there, more could be made in
other places maybe using new technologies. They had a lot of
good public meetings with individual companies, business and
industry representation groups, digested the information and
made some decisions on what they thought was prudent for
Alberta.
SENATOR MCGUIRE asked him to summarize the most important
changes and how long it took to get industry back.
MR. KNIGHT said it took about a couple of months and while there
was never a guarantee in all of their discussions; industry
always indicated that Alberta had good rocks, but what they
needed was taking away the front end load a little bit so they
could find out if the new technologies were applicable to
formations there. So, that is what government did. They gave a
drilling credit for spudding and drilling, but you had to hire a
rig and drill a hole in the ground; it couldn't be used for
anything else. The new well 5 percent royalty became a main
piece that was important at the time, because it helped the
players at the front end. In a lot of cases those energy
companies put that money right back into communities around
North America.
4:03:46 PM
SENATOR MICCICHE said the oil royalty rate dropped from 50 to 40
percent, but the price seemed to be bracketed at $50, $65, $75,
$100 and $120.
MR. KNIGHT said it wasn't bracketed, but it was just a matter of
fitting into the curves. They have old and new oil and tier
three oil, and a bunch of that was wiped away in the later
iterations of the review.
SENATOR MICCICHE asked if the curves were the same.
MR. KNIGHT replied generally, but there were some slight changes
at the top end where they hit the cap.
CHAIR GIESSEL thanked Mr. Knight very much for his remarks.
^Presentation: PFC Energy
Presentation: PFC Energy
4:06:26 PM
CHAIR GIESSEL invited Tony Reinsch, PFC Energy, to talk to them
about capital allocation and global portfolios.
4:06:32 PM
TONY REINSCH, Senior Director, Upstream Group, PFC Energy,
provided a capital allocation and global portfolio review. He
said while PFC Energy has staff geologists and engineers, they
are focused on the above-ground issues, challenges and
opportunities that are being faced by international oil and gas
companies, regulators, governments and national oil companies
worldwide.
He related that he works with the Upstream Group which focuses
on the competitor landscape for the 30 or so largest oil and gas
companies globally and about 25 of the largest national oil
companies. They spend their time trying to untangle strategies,
their growth plans and prospects and occasionally try to lend
advice to the companies on where they might be going and to
governments on how to best get them there.
MR. REINSCH had some thoughts on the Alberta fiscal system he
had prepared last year for the Alaska legislature would be
useful to go through. He started with a presentation entitled
"Exploration Spending in Western Canada." The most material
upheavals in fiscal systems in Alberta were the National Energy
Policy, which was imposed on the provincial government by the
federal government in the early 1980s, and the other was then
Premier Stelmach's sharp imposition and reversal of fiscal
change in the 2006/7 period. Both were the results of economists
and otherwise clear thinking people losing sight for a moment of
the market cycle and getting caught up in the idea that, in the
case of the 1980s and the National Energy Policy, oil prices
would go up forever - requiring a change in the constitutional
fabric of Canada - and the Finance Department's taking a
position that oil production in Alberta would go down forever -
therefore shifting to implement a fiscal regime that was really
predicated on harvesting out the long tail end of a resource
production curve and taking a larger share for the government as
it was produced out. Both initiatives were incredibly ill-timed.
4:10:05 PM
MR. REINSCH explained that the shift in fiscal terms introduced
by Premier Stelmach in 2006/07 at about the same time as ACES
was put in place in Alaska. Both were harvest-type fiscal moves.
The impact in Canada was a very dramatic shift in activity
levels away from Alberta and into British Columbia and
Saskatchewan. The chart on slide 43 showed Western Canadian
exploration spending over the decade 2000 to 2010 broken into
those three areas. Exploration activity recovered by 2010 and
continued to climb. The question is if this relationship is
causual or correlative and did fiscal systems drive all of this
dramatic move or did a lot of factors come together to cause it.
4:11:29 PM
MR. REINSCH said one of the leading indicators that PFC used for
exploration activity in Western Canada was land lease sales (the
bid and bonus structures), and generally speaking Alberta has
led the pack. Probably the sharpest response they saw terms of
companies leaving Alberta was the drop in in lease sales and the
equally dramatic rise to almost two-thirds of lease sales in
British Columbia and Saskatchewan.
4:12:34 PM
Were oil and gas companies just running away from Alberta and
going to B.C. and Saskatchewan? In reality it was oil and gas
companies taking the opportunity to both send a message to the
Alberta government that they weren't happy and also to start
locking up land in what were going to be very important plays -
like the emerging sort of Bakken North/Lower Chinvan Play - in
southern Saskatchewan where shale oil plays are now impacting
oil production throughout the Lower 48 and Canada, and in B.C.
toward the northeast - locking up large prospective shale gas
land that looked perspective for the kind of technologies that
were being matured in the United States but hadn't really made
it to Canada. There were definite opportunities the companies
were chasing. But it was also a convenient time to push back on
the government to suggest that they had miscalculated something
significantly; and that miscalculation was that rather than
being at the tail end of a long resource curve, this industry
was getting ready to reinvent itself on the basis of horizontal
drilling, multi-stage fracturing, smart drill tools and the
other techniques developed and matured in North Dakota and
Montana, but every bit as applicable in Canada. But, while
fiscal systems definitely had an impact here, the biggest driver
"without question in terms of impacting activity levels" was
commodity pricing over that time period.
Another chart showed all exploration development drilling
activity in Alberta excluding the oil sands (because Alberta
treats it as a different business). It showed that the western
Canadian sedimentary basin had become a gas play by 2006 when
oil drilling and production had been in decline for a long
period of time. And from the viewpoint of finance this was an
industry in a permanent, gradual, maturing decline, and
therefore ripe for increase in government take (because it
wouldn't impact any more exploration). In 2006/7 the Henry Hub
natural gas price averaged $6.74/mmbtu and the equivalent
pricing point for Alberta, called CECO-C, was $6.15 (a little
less for transportation). In July of 2008, Henry Hub peaked at
$11.70/ mmbtu, but since the period of December 2008 to April
2012 that same price has averaged under $4/mmbtu. Not only did
the price crater, it stayed there. Not surprisingly, oil and
gas-directed drilling responded exactly the same way.
Oil prices were rising, gas prices were falling. In April 2006
to March 2007, 11,500 gas wells were drilled in Alberta; over
the equivalent period in 2011/12, 1,600 were drilled. What drove
that was the returns coming to natural gas. He pointed out that
one of the sharp distinctions between Alberta and Alaska is
11,000-13,000 wells a year. He said this industry can move money
around very quickly and that shallow drilling is inexpensive and
that makes it a different world.
4:17:51 PM
MR. REINSCH said today's presentation would come in two parts.
He would first discuss PFC's thoughts on how oil and gas
companies really make their decisions in terms of capital
allocation budgeting and long range planning, not only specific
to a given set of activities (such as in Alaska), but how they
allocate their global funds, because the majority of Alaska's
players have global reach in their portfolios. He was also asked
to provide some thoughts around the particular global strategies
in portfolios of three key producers: BP, ConocoPhillips and
ExxonMobil. So, he thought it would be instructive to look at
companies' annual planning cycles that are common to all of the
large oil and gas companies.
The oil and gas annual planning cycle:
Q1: Strategy review and update targeting long range plans
Q2: Session with the Board of Directors where they share their
views and receive directives from that
Q3: Budget preparation
Q4: Budget review and approval
Then the cycle starts again.
4:20:04 PM
During the strategy review and update, companies that
traditionally operate in Alaska take this approach: looking
first to the future of the world and where the industry is going
for a minimum of a decade and as long as 20 years. They look at
the planning environment, key uncertainty forcing factors and
what has really changed and where they might want to go as a
result. So, global economics, supply demand balances and
geopolitics are always very important. This analysis will be
done broadly at first and then in more depth in each of the
areas where a company is operating.
Above ground they look at operating environment ranging from
safety to fiscal terms, market outlook, new resource activity,
if the market growing and competitor landscape, and how a
company is positioned to either gain or lose in that
environment. With all the material pulled together the company
applies its own filters; it has its targets and objectives and
"no go places" that are a CEO's personal preference. Eventually
it comes down to a set of strategic options that it then looks
at in detail.
The budget cycle is when that information turns into capital
allocation. In the accounting cycle the function of corporate
(central agencies within these companies) is really to provide
all of the business units with a set of common assumptions. For
instance this is what we think about oil prices, gas prices, and
about the Middle East. And they feed those down into each of the
business units who in turn will look at their portfolio of
opportunities and they will come up with a long range plan, a
five year plan and a budget. Normally, it's expected that the
budget is the first year of the five year plan, so there is good
continuity and flow. That information and the capital required
to execute those plans are rolled back up to corporate. They
will almost always be well in excess of available capital, so
they are rolled back down to the business units that come up
with a solution.
That solution or long range plan recommending capital allocation
is taken to senior management and then to the board for approval
and on that basis programs are funded and executed.
4:23:37 PM
MR. REINSCH explained that a project attracts capital by the
same basic process. Creation of project approval review
represents discrete business decisions. Each business unit will
send one up to sometimes dozens (depending on how active the
unit is) of these individual project approval requests (PAR).
For example, you may have a project approval request that
relates to the capital required for asset positioning (entering
a new basin and doing initial analysis and seismic acquisition),
another and separate approval request for exploration with an
expected outcome, another approval for appraisal of exploration
success if there is any, and a movement to development. All of
these are stage gates at which point senior management can
approve the next step of development, have it amended, have
activity suspended or decide to exit or divest. A classic
industry example of this is BP's decision to divest the Forties
Oil Field in the UK North Sea to Apache.
He explained that the Forties Oil Field is an Alaska-type asset;
when it was discovered in the early 70s it had 4.5 billion
barrels of original oil in place. BP produced that field until
2003 and sold it to Apache for $670 million when the field went
into decline for a number of years. When the sale was agreed on,
it had 144 million barrels of remaining reserves. In the period
of 2003 to 2012, however, Apache has produced 170 million
barrels of reserves from that field and has estimated that is
has another 150 million barrels. This is a classic case where BP
looked at the world, its portfolio and global assets that were
asking for capital (large scale deep water developments in the
Gulf of Mexico and West Africa) and it made a decision that
production at Forties was at 40,000 barrels a day and (what they
thought) was declining unless significant capital, management
expertise and time was put towards management of that reservoir
and that field. They made the right decision for them to sell it
to Apache. Apache has maintained production from that field at
5-60 thousand barrels a day ever since and have spent $3.6
billion in doing that.
He explained that BP knew the resource was there, but they would
not have done the work Apache did to increase recovery rates.
Companies go through this churning of assets every year.
4:27:42 PM
The business control architecture (portfolio) might look like
this:
Exploration PAR - Appraisal PAR - Development PAR
Appraisal PAR - Development PAR
Basin/Country Entry PAR - Exploration PAR
Year One - Year Two - Year Three - Year Four - Year Five
Approvals for Expenditure (AFE) are listed under those years and
culminate in a budget for each year. As you go forward the
budget gets recalculated.
4:29:17 PM
MR. REINSCH explained that the basis on which this process for
capital allocation leads to investment decisions within basins
and across the portfolio - in Alaska, for instance, an enhanced
recovery project needs to compete against what ConocoPhillips
and ExxonMobil having ongoing elsewhere in Alaska (competition
within the portfolio), is also competing against similar types
of capital expenditures and Capex investment broadly from
exploration through to production activities.
Importantly, capital programs also have to compete against the
other uses of the funds outside of oil and gas activity like
debt repayment, share buyback, and dividend policies. For
instance, over the last 10 years ExxonMobil has spent
significantly more on share buyback and dividends than it has on
oil and gas investment activity, creating an artificial scarcity
of capital. Mr. Reinsch said this company generates so much
money that it could undertake everything that their business
units want, but doing that would be funding potentially
uneconomic or inefficient activities.
MR. REINSCH said the basis on which companies assess the
relative and absolute attractiveness of their portfolio's
constituent parts is in five ways: growth, profitability
(ability to manage the bottom line), efficiency (ability to
manage capital), cash flow and risk.
Growth: Ability to manage the "top line"
-quality of growth: where, how, consistent or not, plowback rate
Profitability: Ability to manage the "bottom line"
-cash flow, net income, production costs
-absolute and on a per barrel basis
Efficiency: Ability to manage capital: growing or destroying it?
Cash Flow: Ability to manage investment/re-investment in the
portfolio
-ability to finance undertakings, making adequate net income,
debt ceilings, are fiscal systems turning against you in core
areas of operations
Risk: Ability to manage a diversified portfolio
-debt to capital ratio, financial flexibility
4:33:03 PM
He said energy companies employ the following variety of
benchmarks to rank their investment opportunities and then
allocate their investment capital to them:
-Payout period: how long to get money back (more critical to
smaller companies).
-Internal rate of return: time value of money; for instance, you
can have your capital exposed for four or five years before
seeing any initial production for oil sands. All those revenues
need to be brought to a single point in time to compare against
other opportunities.
-Net present value: try to bring all activities to a current
point in time.
-Recycle ratio: a popular metric used in the industry is profit
divided by defining the development costs. Basically, corporate
profitability wants that ratio to be greater than one (if they
invest a dollar, they want to get more than a dollar back).
Some metrics are also used for cash flows:
-Availability of free cash flow for follow on or alternative
investments
-Maximum negative cash flow exposure
-Net booked reserves: critically important, because if you can't
book the barrels it has no value to your company
-Capex: incremental costs of the development along with shared
costs of existing infrastructure
4:36:36 PM
Internally, a company will take these metrics and use them to
allocate capital to projects and, very importantly, allocate no
capital to many projects.
For a project to even be eligible for a budget Mr. Reinsch said,
it already has to have passed absolute hurdles; for instance, it
has to have a NPV greater than zero; there has to be an
expectation of net returns generated; you want to see a 30
percent return on investment and possibly a short payback
period.
A company will have a number of metrics across its portfolio
that are used as hurdles: an IRR hurdle rate of return against a
set of capital projects that is stacked highest to lowest.
4:37:57 PM
SENATOR FRENCH asked what happens to this process when companies
want to become joint ventures.
MR. REINSCH replied that within any joint venture technical
planning committees will come together around a set of planned
capital expenditures usually developed by the operator who takes
the lead role and the others contribute. Once the joint venture
committee has agreed, they go back to their respective senior
management teams and boards and try to attract the share of
capital they will have to put up. Often one will see the
planning committee request from a joint venture not being able
to move forward because one or more of the partners simply
doesn't have the capital or disagrees fundamentally with the
direction.
He explained that in many of these joint ventures, the operator
can cash call the participants in the sense that "we're
proceeding; here's the amount you have to pay. If you don't want
to play, that doesn't mean you are out, but it means you will
forfeit the benefit that may come from that Capex spend" - or
some other penalty (for instance, you have to spend three times
your capital allocation upfront cash).
4:39:45 PM
SENATOR FRENCH asked how it works at Prudhoe Bay that has three
major owners: BP, ConocoPhillips and Exxon. How does the nature
of their legal structure enhance or impede the development of
new projects?
MR. REINSCH answered that that he wasn't an expert, but he
thought unanimity was required for approval.
SENATOR FRENCH asked Mr. Reinsch to give some thought to
roadblocks E&P can put in place when you have companies have
wildly different moments in financial time.
MR. REINSCH remarked that they are paragons of internal upheaval
right now.
SENATOR MICCICHE asked if there is a partnership and one has an
IRR hurdle at $60 and one at $80, if there generally is a
compromise or would they go for the highest hurdle.
MR. REINSCH explained that IRR hurdles are established
internally for each company. The project joint venture team will
also have an IRR that truly reflects the economics of the
project itself. It may be difficult to do, but the project has
to live and die on its own merit. A project is ranked at very
different points of companies in their corporate lives. IRR is
an outcome of an individual project, but the corporate IRR for
ExxonMobil versus BP, for instance, for a project in North
America would be internal to its own corporate determination.
4:42:49 PM
He explained that if you rank a series of projects on IRR from
highest to lowest and if you had an IRR hurdle based on
$60/barrel, four or five projects may be undertaken, but all
other projects do not attract capital within that budget. If you
increase the oil price - hence more cash flow and more
investment capital becomes available - you will tend to see a
reduction in that hurdle rate as companies feel themselves able
to take on more projects that perhaps have a lower threshold in
terms of IRR because they are now in a higher revenue
environment. However, as prices get to $120/barrel (recent Brent
crude) if you didn't put some sort of break on that, all
projects could be undertaken and hence the larger E&P companies,
international oil companies in particular, take very large
shares of their revenue and distribute them back to shareholders
to artificially create some scarcity in capital allocation to
make sure they are being efficient as they make these decisions.
Efficiency in capital allocation measures for the big three
companies in Alaska vary from those of a smaller independent -
the tradeoff being efficiency and growth. It is measured by
return on capital employed (measuring the profit being generated
by a company divided by how much capital is being exposed).
Capital can be measured in terms of the value of assets and
investments or in terms of share capital, reserves and debt.
Basically, the higher the return on the capital employed, the
more efficiently you are using your capital and that metric
changes over time revealing whether profitability is improving
or eroding, and if it's eroding, what are you going to do about
that.
MR. REINSCH next showed a chart of upstream corporate return on
capital employed for what PFC calls the "global players" in
terms of size, reserves and et cetera. Another chart showed the
Tier I independents, a large group of independents that are
within striking distance of 1 million barrels a day production.
They consistently have a very different return on capital.
The period of 2009-2011 showed a little over 20 percent growth
for the global companies; for the Tier I independents it was a
little over 11 percent and the next group drops down to 9
percent. However, what the smaller companies give you is growth.
One of the anomalies in this industry is to find a company with
both high return on capital employed and high growth. The reason
comes out of the equation of "return on capital employed."
Basically this penalizes major capital investments. So, anything
that makes the denominator bigger makes the return on capital
employed smaller. On the other hand, it benefits from anything
that makes the numerator (higher volume) larger. Large capital
projects tend to be structured with three to five years of very
intensive capital spend during which the return on capital
employed is being drawn down, because you're investing heavily
with no return, followed by (generally speaking) high production
from that investment, because companies want to get the money
back as fast as they can - outside of a very few projects such
as mined oil sands plants and LNG facilities.
4:48:19 PM
So companies move in and out of that space of high return/low
return on capital employed and high/low growth.
Importantly for Alaska, Mr. Reinsch said, depreciation creates
bias in favor of a mature portfolio, so the older your assets
the better return on capital employed, because the denominator
has been accounted away. So, all else being equal, your return
on capital employed is improving just by doing nothing other
than maintaining activity levels (and price).
4:49:34 PM
Shifting gears, Mr. Reinsch spent some moments talking about the
portfolio strategy of Alaska's three major players. He said it
is remarkable that these are three of the ten largest
international oil and gas companies globally that have all over
the last three to four years been subject to and continue to go
through transitional change in strategy, in positioning and
approach to the future. These are companies you would expect to
have everything thought through and in control of the situation,
including ExxonMobil, which has once again become the largest
publicly traded company in the world with the collapse of Apple.
4:51:37 PM
He next talked about how Alaska fits into these portfolios
starting with BP saying everyone was familiar with the Macondo
blowout in the Gulf of Mexico, which triggered a transformation
of BP. BP largely addressed the liabilities stemming from that
incident by pledging point forward production from its very
large and lucrative Gulf of Mexico portfolio to the Macondo
fund.
This company took advantage of a period of upheaval and change
to fundamentally restructure their global portfolio, taking some
$26 billion of divested assets globally, entire portfolios in
the Asia/Pacific region, the majority of their conventional
onshore oil and gas in North America, stripping all of those -
what they considered mature non-core immaterial assets - out of
their portfolio and buying back or reinvesting in about $30
billion in new positioning in new basins with new companies,
like their joint venture with Reliance in India. So, they came
out with a smaller portfolio, but a much more growth oriented
one than prior to Macondo, and interestingly not only
recommitting to their deep water basin growth platform, but in
fact deepening their commitment to deep water activity. This is
the outcome of a company that many were suggesting would be
broken up or never allowed to operate in deep water again.
BP has a three-pronged growth strategy that continues in deep
water basins, global gas and giant oil fields, and Alaska fits
in the later currently and may fit in the second category of
global gas depending on the future of LNG in this state.
He said BP's most recent move was the sale of its interest in
the TNK-BP consortia in Russia that will net the company some
$22 billion. By doing so, BP will become arguably the second
private company to make money in Russia (the first being
Marathon, which made money by buying and selling out of Russia
twice). As a second step, BP is looking to take an equity stake
(20 percent) in Rosneft, the acquirer to TNK-BP moving them into
much more perspective growth areas and solidifying their
position in the Arctic resource development - sort of the long
run play of which Alaska is a part, as is northern Canada,
Norway and Russia.
4:56:19 PM
CHAIR GIESSEL asked why Alaska was shown as a harvest area for
BP on a slide he presented on April 21, 2012, eight months ago;
but now it is shown as a core area. What changed?
MR. REINSCH explained that in that material Alaska was broken
out from the U.S. in BP's portfolio as a harvest area as it
exists today, but the U.S. is core to BP. Alberta was a harvest
area for 15 or so large players until the technology of
horizontal drilling and multistage fracturing and smart drill
tools allowed them to access shale oil, tide oil and shale gas.
Everyone knew it was there, but they just didn't know how to
produce it commercially until the technology developed to that
level. As an example, a material LNG development in Alaska would
become core to the company's future.
CHAIR GIESSEL asked if by showing Alaska as core on the current
map was he combining it with the U.S., but if he were to
separate it out, would it still be harvest.
MR. REINSCH answered yes.
CHAIR GIESSEL said earlier he had mentioned that ACES was a
"harvest type of a fiscal regime" and asked if that was the
element that would make made Alaska a harvest area or if there
are other factors.
MR. REINSCH replied that a harvest area may continue to have
capital investment, but the production is in a sustained and
unlikely-to-be-reversed decline and the free cash flow being
generated is being moved outside of the jurisdiction and
invested elsewhere.
4:59:45 PM
SENATOR FRENCH said last year this committee was presented with
a 2004 BP memo, which predates ACES by three years, that said
Alaska's role in BP's portfolio is to provide a stable
production basin cash flow to fuel growth elsewhere in the
business. So it was in harvest mode even back in 2004.
MR. REINSCH replied that is consistent with how they define
harvest mode. To re-interpret the bars, 2001 is the lightest
blue, 2011 is the middle blue and 2016 is PFC's forecast using
their modeling of the global portfolios of the global companies.
PFC models all current producing assets and all discovered
and/or underdeveloped resources in each of these companies'
portfolios annually. This analysis excludes the TNK-BP sale
which concludes at the end of this quarter. BP has said their
intention is to have a production floor of around 2.4 million
barrels a day following the TNK-BP divestiture that will take
about 1 million barrels a day of production with it. Post the
TNK-BP divestiture, BP will be a materially smaller company
pending their equity investment in Rosneft.
5:02:11 PM
He said this chart showed where BP is looking to grow on a
regional basis, and their growth is likely to come from North
America (Gulf of Mexico deep water and Lower 48 on shore) and
Latin America where it may be larger depending on how
aggressively they engage in joint venturing of strategic
associations with Petrobras in the Brazil pre-salt deep water
play. By acquiring the $30 billion of assets, BP is positioned
aggressively in that particular deep water basin, consistent
with their growth platform.
TNK-BP in Russia was a mature portfolio and one of their
challenges was limited growth in terms of opportunity, but they
also faced a very difficult fiscal environment in which it was a
struggle to show growth or return on capital employed.
They are hopeful that by re-investing in Rosneft that will
change.
MR. REINSCH said BP is churning their assets in regional areas,
which usually means for companies of this size is that they are
investing to keep up with decline. It's hard to grow a large
portfolio significantly.
CHAIR GIESSEL said in being able to look at his presentation
eight months ago and now she appreciated how dynamic all of this
is. For instance, on April 21, Azerbaijan (Central Asia) was the
largest source of new source volumes through 2015 and that
changed very rapidly in just a few months.
MR. REINSCH agreed and added that this chart doesn't make clear
that these numbers show the net outcome of portfolio decline and
new source production. If they looked at simply new source,
incremental production going forward, Russia absolutely was the
largest area of new source even though overall production wasn't
expected to move very much. That is because the active onshore
basins were TNK-BP that is very mature. It's hard to keep up
with the decline, but if you do, that means you are generating a
lot of new production. And if the Rosneft deal doesn't
transpire, then BP will have $22 billion to do something else
with.
5:07:00 PM
The next slide was PFC Energy's assessment of how BP fits
Prudhoe Bay into its global portfolio. They see it as a harvest
asset; production volumes are modest and have been declining for
a while. There is long term potential in Prudhoe Bay and Point
Thomson gas resources, because with the Denali Pipeline now
canceled, BP is positioned as a potential supplier to some
alternative commercialization options such as a large pipeline
LNG scheme that would access high value markets in the Asia
region.
BP's Challenges:
-Portfolio rationalization is coming to an end. Analysts are
looking at how to re-ignite growth.
-BP needs a new core area if Russia isn't going to be one. Even
in the absence of that they are heavily exposed in the deep
water in a couple of areas. The deep water partnership with
Petrobras may be that new core and they have enormous
unconventional gas resource holdings and unexplored acreage in
the Lower 48 and the Canadian oil sands where they have been
relatively slow to develop on their leases for whatever reason.
5:09:43 PM
Shifting to ConocoPhillips, Mr. Reinsch said, their upheaval has
been equal if not greater than BP's. Just a few years ago, mired
in low share value and uncompetitive earnings multiples, they
embarked on a different strategic pathway - the shrink to grow
strategy. They essentially sold $15 million of joint venture
obligations and assets and returned those funds to shareholders
one way or another, either through dividends, buybacks or debt
reduction. Part of that was their 20 percent equity investment
in LUKOIL in Russia and repositioning their global portfolio to
a focus on the OECD or industrialized companies, a relatively
safe haven when other competitors were taking on more and more
above ground risk (moving into Interior Africa, the East Coast,
and the Middle East). These areas all tend to be expensive and
very competitive in terms of accessing acreage and opportunity.
It's not a low cost strategy, but a differentiating strategy.
Then in July 2011 they took the step of separating the company
into two distinct entities: Phillips 76 (downstream assets) and
ConocoPhillips the largest pure play independent oil and gas
company. The question now is where this company is going from
here as it is very difficult to take a company like this apart.
Their latest corporate investor presentation of 2013 will be
their bottom point with some growth returning over the
subsequent two to three years.
5:12:47 PM
ConocoPhillips' global portfolio includes Canada, United States,
Norway, and the United Kingdom and a number of areas where the
company is looking to exit (as is the case in Russia).
ConocoPhillips has now moved out of the group of global players
and into a new competitor space which are the independent oil
and gas companies of which it is the largest. Its peers are: BG
Group, Occidental, Apache, Anadarko and Suncor.
SENATOR FRENCH asked if the Burlington Resources purchase was a
good move.
MR. REINSCH replied it was a good move but bad timing. In 2006
ConocoPhillips found itself in the "never, never, land" which is
they were much larger than the next group down of independent
and integrated oil and gas companies, so they couldn't compete
with them on growth. Their production was too large to grow it
3-5 percent whereas the smaller companies can do that. But their
portfolio wasn't deep enough with large scale capital projects
to compete with the big super majors on return on capital
employed and they found it was hard to get the value they
believed was in their portfolio reflected in their share price.
So they bought Burlington Resources, a big North America
conventional oil and gas player. Unfortunately, that acquisition
closed within a month of the peak of the gas price in the U.S.
They thought prices were going to stay at these high levels if
not increase further, because demand was strong, but within
three years of shale gas commercialization the bubble was gone.
Demand is still there he said. The collapse in the U.S. gas
prices is absolutely not a demand story; it is completely a
technology and supply story. ConocoPhillips was just at the
wrong moment and has spent the last few years trying to manage
that decision.
5:16:42 PM
MR. REINSCH said ConocoPhillips is a significant Asia player,
but its dominant position is in North America having exited out
of Central Asia and Russia in 2011. Unlike BP, Alaska is core
ConocoPhillips' portfolio; its core to their strategy and to
their significantly smaller global production base; hence it is
viewed differently within their decision making process.
SENATOR FRENCH said ConocoPhillips is the only one of the three
majors in Alaska that reports its Alaska numbers separately and
a document with those numbers was run through Legislative
Research a couple of times and come back with really strong
profit numbers in Alaska relative to ConocoPhillips' holdings in
other parts of the world. He wanted to ask him at some point in
the future whether that was accurate and how that might affect
ConocoPhillips's investment strategy in Alaska.
5:19:21 PM
MR. REINSCH went on to ExxonMobil that has been the most
surprising circumstance of dramatic portfolio change, because
it's not a company that wants its text to change in any
substantive way. It found itself in a "bit of a box." The decade
of very strong growth that ExxonMobil delivered until 2011 was
really driven largely by their very large LNG portfolio in
Qatar. The Qatari government put a moratorium on incremental
further development from their enormous North Field gas resource
base that continues today. So, that growth engine ended for
ExxonMobil in 2012 when the last of their LNG trains and
developments came on stream. So facing a flat production future
in Qatar, declining production from both Europe and Asia
Pacific, the company looked elsewhere for growth.
5:20:56 PM
Venezuela had been closed and ExxonMobil was unable to strike a
deal with the new Chavez administration some years ago when it
exited the country. Brazil deep water looked to be the perfect
growth platform for ExxonMobil until the government introduced
new legislation that gave Petrobras operatorship and a 35
percent working interest in all future licenses and developments
in the very large pre-salt deep water play. ExxonMobil is not a
non-operator participant when it can avoid doing so, so Brazil
has become much less interesting to them. They tried to position
in the equatorial margin, a frontier basin that is being de-
risked, but was rebuffed by the Guyanese government when it
tried to buy its way into the Jubilee Development in the
offshore gas resource.
Where is a company of ExxonMobil size going to grow? They took a
daring move and aggressively positioned themselves in
unconventional resource play in North America through the
acquisition of XTO Energy, really exposing this company
substantially into an area that is not what it has been known
for (big large scale field developments, execution excellence
and cost control and reduction). Moving instead into an area
that may have large global reach, but it involves tread mill
drilling, moving capital very aggressively from play to play and
sub-play to sub-lay, a minute micro focus on capital and
drilling costs that are very much changing how this company is
looking to grow moving forward.
MR. REINSCH said ExxonMobil is the largest of the global players
by a significant margin. The XTO purchase had material impact on
it and in 2010 BP moved slightly above ExxonMobil in terms of
total production.
5:23:16 PM
Regional growth trajectories are continuing to decline in
Europe, flat production for Middle East and North Africa (really
meaning flat production in LNG developments in Qatar), but big
annuity projects. Interestingly, their growth is really coming
from North America. It's interesting to see the biggest of the
big moving back to their home basins to take advantage of the
technological changes to fuel their growth for the upcoming
decade (oil sands development).
5:24:01 PM
SENATOR MICCICHE asked what "other" means in terms of
"technological competencies" for ExxonMobil.
MR. REINSCH answered that it is a grab bag of "other" categories
that ExxonMobil exploits at the technology margin, or the
frontier, instead of predominantly conventional oil or gas
plays. In ExxonMobil "other" is a very small amount of future
looking technology.
5:25:00 PM
He said that PFC sees Alaska as a harvest area within
ExxonMobil's overall globally portfolio subject to that same
proviso of changing opportunities like commercialization of the
large gas resource base in this country.
5:25:47 PM
SENATOR FRENCH asked what it suggests if Prudhoe Bay investment
decisions require all three partners to agree and yet by his
analysis, two out of three view Alaska as a harvest area and one
perhaps wants to be more aggressive.
MR. REINSCH answered the combination of unanimity within the
joint venture and also the absence of any sort of relinquishment
provisions creates an environment where capital needs to be
attracted by being competitive. Higher prices and changes in
fiscal terms may or may not move that lever. None of the
companies individually can guarantee that any change that takes
place is going to result absolutely in a certain action
response. "Unanimity makes it harder," but is a facet of that
agreement that has been in place from the beginning, so much has
been invested and done to the benefit of the state with that
structure.
CHAIR GIESSEL thanked Mr. Reinsch.
5:27:38 PM
At ease from 5:27 to 5:34 p.m.
SB 26-LAND DISPOSALS/EXCHANGES; WATER RIGHTS
5:34:19 PM
CHAIR GIESSEL announced the consideration of SB 26 and opened
public testimony.
ANDY ROGERS, Deputy Director, Alaska State Chamber of Commerce,
stated that for the last several years regulations and
permitting processes have risen to being the top three state
priorities for the Chamber and the membership generally supports
SB 26. He applauded DNR efforts to evaluate processes and make
incremental improvements to make Alaska more successful.
5:36:46 PM
LISA WEISSLER, representing herself, Juneau, AK, said she has 20
years of natural resource experience as an attorney. She
reviewed the bill section by section and had suggestions to
amend each.
She started with the general permits section and said this
section gives the commissioner the authority to authorize
activities through a general permit if the commissioner finds
that the activity is unlikely to result in significant and
irreparable harm to state land or resources. The laws generally
will help establish a consistency and predictability in agency's
decisions which is important to the public, the agencies and the
applicants. But here, according to DNR, decisions about what
constitutes a significant and irreparable harm is going to be
made on a case by case basis, which creates the potential for
inconsistency and uncertainty in decisions made by both this
commissioner and future commissioners.
If general permits are going to be allowed, a better approach
might be to establish them as a separate provision in law that
identifies what activities qualify and the process for
establishing the permits. The DNR currently has a regulation
that specifically identifies activities that don't require any
permit, so she didn't think it unreasonable to ask to have the
same level of clarity here.
Moving on to appeal rights that are all through the bill,
currently a person who is aggrieved by a DNR decision generally
has the right to appeal to the agency. The legislation changes
that so that a person must be substantially and adversely
affected, and that will be determined on a case by case basis,
which creates a potential for inconsistency and possibly
inequitable decisions in how the statute is applied.
On Monday, Mr. Menefee said there is a problem because some
people say they don't like the decision and that's all they get.
But most people aren't well versed in state permitting law; they
don't know it like the agencies do, so they don't know how to
make their appeal more effective and they do what they can. Now
DNR is asking them to describe how they are substantially
affected without any definition about what that means; DNR
doesn't seem to know what that means either. He also said there
are about 43 appeals a year out of the hundreds of permitting
decisions they make. Out of those 43 about 25 percent of the
people don't have anything more to say than that they don't like
it; maybe 10 a year. So, it doesn't look like this is really a
big enough problem to make such a big change.
MS. WEISSLER said the reservation of water section is a solution
seeking a problem and DNR really just needs the staffing to
process reservations. In terms of tendered water use permits,
the proposed language gives the commissioner the authority to
issue an infinite number of temporary water use authorizations
and Mr. Menefee said it's a better way to do it, because the
state retains control of the water. But the problems are with
the temporary water use statutes, because while you can make
adjustments whenever a new permit is being issued, that is
discretionary on the part of the commissioner, but the public
never gets a chance to weigh in on issues the department might
not know about. A better way to do this is something in between,
she said, if DNR wants to authorize a temporary water use that
has passed five or ten years but not a water right
appropriation, then develop a permit that includes public notice
and criteria.
5:41:43 PM
JAMES SULLIVAN, Legislative Organizer, South East Alaska
Conservation Council (SEACC), testified in opposition to SB 26.
He said the proposed revocation of all personal use reservations
is problematic. SEACC wants to ensure that the environment is
protected and that anadromous streams have highest priority when
permits are issued. He proposed that when any entity applies for
a water right on an anadromus body of water, that DNR issue a
water reservation on behalf of the fish; it can refer to the
Anadromus Waters Catalogue, which is already there; once they do
that they can put in an appropriate reservation. This would
align DNR with the State Constitution, Article 8, Section 3, on
the common use issue and protect its public trust
responsibility; it would ensure protection for our salmon and
enhance sustainable economic development across the state as
salmon is our greatest renewable resource. It is in the state's
best interest to put a mechanism in statute to protect the fish
resource as other entities apply for water rights.
He also noted that DNR had spoken at length about permitting
problems, yet the 2012 Frasier Institute Report ranks Alaska
fourth in the mineral entities around the world when combining
the composite policy and mineral potential; over 90 different
regions in the world fall below us. He expressed hope that the
committee would address that great discrepancy when the CEO's
who fill out Frasier's form rank Alaska so high and the DNR
commissioner provides such a low response.
5:45:01 PM
HAL SHEPHERD, Center for Water Advocacy, Norton Bay Intertribal
Watershed Council, and the Native Village of Elim, Seward, AK,
testified in opposition to SB 26. He expressed concerns
regarding past hearings in which statements by the Division of
Mining, Land and Water as to who this bill would affect,
particular in reference to the limitations on who can now apply
for in-stream flows. The testimony he had heard so far
noticeably omitted Native Alaskan tribal governments of which a
few had applied for in-stream flows on waters in Alaska
specifically to protect subsistence uses. But there has been no
discussion about the fact that this bill would limit those
applicants, including several tribes who have already submitted
applications, from applying for in-stream flows. This seems to
be a continuation of the administration's efforts to privatize
water rights in Alaska, but also severely limiting the standing
for individuals who can appeal applications that have been
issued for mining permits, oil and gas drilling or hydro power
plants, which again noticeably leaves out the substantial
majority of individuals, tribes or NGOs who may be impacted by
the issuance of such water rights.
MR. SHEPHERD urged the committee not to strip the rights of
individuals' constitutional rights, specifically Article 8,
saying the state can issue water rights subject to a general use
for fish for all of Alaska's citizens.
RICK ROGERS, Executive Director, Resource Development Council
(RDC), Anchorage, AK, testified in support of SB 26. He said RDC
is a statewide business association representing the forestry,
oil and gas, mining, tourism and fishing industries with the
overall of mission to grow Alaska through responsible resource
development. One of their top legislative priorities is to
encourage the state to promote and defend the integrity of
Alaska's permitting process and to advocate for predictable
timely and efficient state and federal permitting processes
based on sound science and economic feasibility.
He said the legislature to its credit provided DNR with
additional resources in past years to address what had become an
untenable backlog of permits and authorizations. Such backlogs
negatively affect our resource industries, but they also affect
many individual Alaskans who are seeking the required state
authorizations. It's important to recognize that Alaska land
entitlement is over 100 million acres plus jurisdiction over
submerged lands and the permits that DNR adjudicates go far
beyond the mineral industry and he was puzzled why the
discussion is so focused on that one industry. He was also
curious about how permits are adjudicated for mining projects
versus everyday Alaskans trying to cross tidelands to get to a
dock.
MR. Rogers said ramping up staff to adjudicate the backlog was a
great idea, but it's addressing a symptom rather than systematic
improvements. Now, we have a very complex set of statutes that
have been developed over five decades of statehood and they need
some improvements. Commissioner Sullivan had done a good job of
identifying specific means of improving the efficiency of this
complex system and the administration should be applauded for
proposing numerous changes to DNR enabling statutes in order to
make their processes more timely and efficient.
CHAIR GIESSEL closed public testimony and held SB 26 in
committee.
5:53:05 PM
There being no further business to come before the committee,
Chair Giessel adjourned the Senate Resources Standing Committee
meeting at 5:53 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SRES Alberta's Natural Gas & Conventional Oil Investment Competitiveness Report 2010.02.16.pdf |
SRES 2/6/2013 3:30:00 PM |
|
| SRES Calgary Herald-Alberta Land Sale 2011.03.23.pdf |
SRES 2/6/2013 3:30:00 PM |
|
| SB 26 Opp Letter RobertaHighland Kachemak Bay Conservation Society 2013.02.04.pdf |
SRES 2/6/2013 3:30:00 PM |
SB 26 |
| SB 27 Opp Letter RobertaHighland Kachemak Bay Conservation Society 2013.02.04.pdf |
SRES 2/6/2013 3:30:00 PM |
SB 27 |
| SB 27 Support AOGA testimony 2013.02.04.pdf |
SRES 2/6/2013 3:30:00 PM |
SB 27 |
| SRES PFC Energy. T Reinsch 2013 02 06.pptx |
SRES 2/6/2013 3:30:00 PM |
|
| SB 26 City of Elim Resolution # 13-03 2013.pdf |
SRES 2/6/2013 3:30:00 PM |
SB 26 |
| SRES Alberta Experience Mel Knigh 2013.02.06.pdf |
SRES 2/6/2013 3:30:00 PM |