Transcript Title

North American Natural Gas
Fundamentals and Market
Based Long-term Pricing
Tommy Inglesby and Ankush Kumar
McKinsey & Company, Inc.
November 16, 2007 – Houston
Baker Institute/CEE Energy Forum
© 2007 McKinsey & Company, Inc. No part of this report may be circulated, quoted, or reproduced for
distribution without prior written approval from McKinsey & Company. This material was used by
McKinsey & Company during an oral presentation, it is not a complete record of the discussion. The views
expressed herein are based upon assumptions as to marketplace evolution and dynamics, and other factors
which are inherently uncertain and are subject to change. There can be no assurance that all such
assumptions will in fact be borne out, and, in fact, it can be anticipated that the assumptions will be subject
to change over time.
PERSPECTIVES ON NATURAL GAS PRICES
Market based perspective on gas price: Estimating long-term gas price
and probability distributions based on commodity and capital markets
Gas price fundamentals: What you would need to believe to see a
sustained gas price linkage to petroleum conversion capacity
Questions
1
CONSENSUS ESTIMATES INDICATE A SHIFT IN LONG TERM GAS PRICE
PROJECTIONS
Current forward
HH spot
Historical forwards
NYMEX Henry Hub (natural gas) price
$/MMBtu
15
Historical
Futures
Industry estimates
for 2015-2030
Average market price
$, MMBtu 2015-2030
EEA
10
EIA
GII
7.70
SEER
6.68
GII
6.72
EEA
SEER
5
Previous futures range
0
EIA
6.08
Wide range of future
gas price range
1995
2007
2013
* EEA = Energy and Environmental Analysis, GII = Global Insight, Inc., SEER = Strategic Energy and Economic Research, EIA = Energy
Information Administration
Source: NYMEX, EIA, Team analysis
2
LONG LIVED E&P ASSET VALUATIONS PROVIDE THE CAPITAL MARKETS
PERSPECTIVE OF LONG TERM GAS PRICE –
EXAMPLE DEAL
Production profile
Gas price assumptions
Reserves
• 0.6 tcf of proven reserves
• 1.4 tcf of unproven reserves
Long-term
price
10
9
8.00
8
Development and operation
costs estimates
• Reserve risk factor
• Drilling profile
• Well production costs
8.00
7
6
6.75
5
Forward
curve for
first 5
years
4
3
2
Production profile
Mmcf/d
1
00
400
300
200
0
Source:
McKinsey Analysis
0
6.75
5.50
5.50
Long-term price
for 5+ years
40
Transaction value
($2.2 Billion)
Implies an embedded
long tern gas price of
$6.75/MMBTU
100
0
Asset value
$ Billion
2036
3
SIMILAR VALUATION OF OTHER LONG LIVED GAS EXPOSURES
INDICATE LONG TERM GAS PRICE RANGE OF $6.50-7.50/MMBTU
$ Millions
Long life E&P
Transactions
Deal 1
790
Deal 2
2,200
Deal 3
945
Company
Enterprise value
$ Millions
E&P Company A
4,000
E&P Company B
7,500
E&P Company C
8,000
E&P Company D
4,500
Utility
Source:
Asset value
$ Millions
McKinsey Analysis
45,000
Implied long-term price
$/MMBTU
7.00
6.75
7.25
Implied long term price
$/MMBTU
7.00
• Narrow range
of long term
implied gas
prices
• Implies a long
term gas price
6.50 to 7.50
$/MMbtu
7.25
6.75
6.50
7.50
4
MARKET OBSERVATIONS CAN BE COMBINED TO ESTIMATE GAS PRICE
PROBABILITY DISTRIBUTION
Stochastic simulations
with market based
inputs inputs
• Expected Price
– Near term :
Forward prices
– Mid- long term:
Fundamentals
combined with
long term price
embedded in
E&P company
valuation
• Price volatility
– Option implied
volatilities combined
with mean reversion
from price history
Simulated natural gas price* distribution
$ / MMBtu
$25
$20
<5% probability of
gas price being
above 13 $
/MMBTU in 2018
$15
$10
<5% probability
of gas price being
below 3.50
$/MMbtu in 2018
$5
$0
2007
Source:
McKinsey Analysis
2009
2011
2013
2015
2017
5
PERSPECTIVES ON NATURAL GAS PRICES
Market based perspective on gas price: Estimating long-term gas price
and probability distributions based on commodity and capital markets
Gas price fundamentals: What you would need to believe to see a
sustained gas price linkage to petroleum conversion capacity
Questions
6
SINCE 2000, NATURAL GAS PRICES HAVE TRADED WITHIN THE BAND OF
#2 Distillate
A RESID FLOOR AND A DISTILLATE CEILING
Natural gas
#6 Resid
US Gulf Coast gas and energy NYMEX prompt month prices*
$/MMBtu
Coal
16
14
• Natural gas priced between
• Natural gas priced
resid and coal
Refining margins were tight
between resid and
distillate
Refining margins
were wide
•
•
12
$10+
Crude linked
• Do gas prices
stay linked to
resid in a high
crude price
environment?
10
8
$6-8
Gas on gas
6
• Do gas prices
4
fall to gas or gas
competition / or
crude prices
decline
significant?
2
0
1992
1994
1996
1998
2000
2002
2004
2006
* Converted at EIA heat content of 6.287 for No. 6 low sulfur and 5.825 for No. 2. Coal prices shown as delivered spot prices to Northeast. Does not
include estimate NOX and SOX costs
Source: Bloomberg; McKinsey Analysis
7
SIGNIFICANT GENERATION INVESTMENT WILL SOON BE REQUIRED;
IF NUCLEAR AND COAL PLANTS CANNOT BE PERMITTED,
CCGT BECOMES THE DEFAULT CHOICE
Economic fuel choice*
Capacity to meet minimum U.S.
power reserve margin of 15%
GW
CO2 price
$/ton
60
Nuclear
favored
50
By 2015
125
40
Natural gas
(CCGT) favored**
30
20
By 2020
225
Coal (SCPC)
favored***
10
0
0
2
4
6
8
10
12
14
Natural gas price
$/MMBtu
*
**
***
Source:
All plants use 9% WACC and 30-year life
CCGT at 7,000 Btu/kWh heat rate; $800/kW nominal greenfield Capex; 90% capacity factor; 3-year time to build
Coal at 9,100 Btu/kWh heat rate; $2,100/kW nominal greenfield Capex; 92% capacity factor, 4-year time to build; $75/MMBtu coal
EIA; McKinsey
8
A SIGNIFICANT GROWTH IN GAS DEMAND CREATES A SIGNIFICANT
SUPPLY GAP THAT MUST BE MET
Bcfd
New demand drivers acting on top of traditional growth
engines…
Power
• High demand growth (1.8% per year)
• Difficult to permit new builds for nuclear
…increase demand growth, implying a potential
supply gap of ~37.5 Bcfd by 2015
Demand
20061
73
and coal plants
• Growth in power demand met almost
entirely by gas through higher utilization of
existing CCGT gas plants and new gas
fired plants
Oil Sands
• Rapid increase in oil sands production
•
(projections of 3-5 million bpd by 2020)
Production requirement of 0.75 mcf per
barrel of oil
Traditional growth 2
7
Power3
12
Oil sands4
2.5-4.0
Ethanol5
2-3
2020 demand
Ethanol
• North American ethanol demand assumed
•
to reach 15 billion gallons by 2015 and
grow to 30 billion gallons by 2020
Production requirement of ~1 cm of gas
per gallon of ethanol
98
Supply
2006 production
2015 supply gap
70
28
1 November 2005 to October 2006 EIA reported demand for US
2 EIA estimate of 1.6% growth in US, 2.4% growth in Canada
3 Assumes historical capacity creep for nuclear and coal capacity and utilization, with 30GW new coal build. Assumes renewable growth to 50 GW of capacity (7% of US power consumption). Remaining demand met by new CCGT at
7000 Btu/kWh Heat rate. Assumes 75% increase in gas-to-power demand growth met by capacity creep and new CCGT.
4 Assumes accelerated growth as Oil Sands development to 6.6 MMBd of production by 2020, utilizing 13 cm per barrel of oil
5 Assumes US achieves 20 BGY ethanol standard by 2015, growing to 30 BGY by 2020 – results in incremental 2 bcfd of natural gas demand by 2015 and 3 bcfd by 2020.
Source: EIA Annual Energy Outlook (2006); National Energy Board of Canada; MMS Deepwater forecast; Renewable Fuels Association; BP Statistical report 2006; press clippings McKinsey analysis
9
THE INCREASING SUPPLY GAP WILL DRIVE SIGNIFICANT E&P ACTIVITY
AND REQUIRE ATTRACTING ADDITIONAL LNG VOLUMES FROM EUROPE
Within ten years, over 60% of the production will come from
new wells in existing and YTF* fields as well as LNG …
E&P activity will increase dramatically
Number of new wells drilled per year
+10%
NA Natural gas supply requirements
Bcfd
70,000
30,000
120
Net NA Natural
gas demand, ~3% CAGR
100
2006
Gap to be filled by
new resources and
LNG
80
60
New prod from
existing onshore fields
40
Existing onshore** prod
Canada production
20
Offshore***
0
2006
*
**
***
Source:
2008
2010
2012
2014
2016
Yet To Find
Assumes hyperbolic decline from IHS 2006 survey
Estimate from EIA/MMS
EIA Annual Energy Outlook (2006); Wood Mackenzie; MMS Deepwater forecast; McKinsey analysis
Rigs
Average
rig count
1400
2015
2550
High US prices required to attract LNG:
• Limited LNG liquefaction capacity
worldwide; NA plus Europe demand
LNG regas capacity to exceed
liquefaction capacity
• US gas prices will likely be above oil
parity (Europe prices) to attract LNG
cargos
10
LNG PRICES IN A SHORT ENVIRONMENT RISE TO THE VALUE IN
ALTERNATE MARKET – IN THIS CASE EUROPE
ILLUSTRATIVE
Oil-linked pricing band
2012 North American Natural
gas supply and demand curve
$/MMBtu
14
Nonswitching
demand
If Demand stays
robust and US supply
not sufficient to push
LNG back into the
Atlantic, the marginal
price setter for the US
becomes LNG
competing with
Europe
Distillate switching
12
Power dispatch
switching
10
4
2
Indigenous supply
marginal lifting costs
0
30
40
50
North American gas volumes
Bcfd
Source: McKinsey
60
70
80
LNG Imports
(competitive)
LNG Imports
(fixed)
6
Indigenous production
Resid switching
8
90
11
PERSPECTIVES ON NATURAL GAS PRICES
Market based perspective on gas price: Estimating long-term gas price
and probability distributions based on commodity and capital markets
Gas price fundamentals: What you would need to believe to see a
sustained gas price linkage to petroleum conversion capacity
Questions
12
UNUSED SLIDES
13
IN EUROPE, NATURAL GAS CONTRACTS INDEX PRICES TO LOW
SULFUR FUEL OIL PRICES
Brent
$ / MMBtu, 1991-2006 Q3
Oil-linked gas price (WGI)*
Low Sulfur Fuel Oil (LSFO)
Oil-linked gas border price* compared to Brent and LSFO prices
Oil-linked gas prices reflect longrun marginal cost of Europe’s next
alternative supply (Russia)
12
Growing price gap to gas
cost as oil prices
increase and stay high
10
8
50 $/bbl ($6.65/MMBtu)**
6
40 $/bbl ($5.25/MMBtu)**
30 $/bbl ($3.90/MMBtu)**
4
20 $/bbl ($2.50/MMBtu)**
2
06
Jan-06
05
Jan-05
04
Jan-04
03
Jan-03
02
Jan-02
01
Jan-01
00
Jan-00
99
Jan-99
98
Jan-98
97
Jan-97
96
Jan-96
95
Jan-95
94
Jan-94
93
Jan-93
92
Jan-92
91
Jan-91
0
Cost of Russian
imports (full cost)
* Monthly prices. Gas prices average for Spain, Belgium, Netherlands, Germany, Italy, France & UK . 6-month lag compared to oil (Brent) and LSFO
** Assumes 6.287 MMBtu / Bbl for LSFO, FCC is marginal refining unit in Europe, and an average of narrow and wide light / heavy differentials (modeled)
Source: Platts; World Gas Intelligence; EIA; McKinsey GGM; McKinsey refining equilibrium pricing model
14
LIQUEFACTION ACROSS THE ATLANTIC IS CONSTRAINED AND WILL
NOT BE SUFFICIENT TO FILL US REGAS CAPACITY
Atlantic Basin Liquefaction and regas capacity*
Bcfd
• Natural gas delivered
into Europe currently
prices at a residual
fuel oil linked contract
price
40
35
30
North America
• If the US prices below
25
17
19
19
19
14
Atlantic basin
liquefaction
20
18
19
11
15
8
10
5
resid, then more
majority of excess
LNG should divert to
Europe
2
5
2
5
3
5
3
6
4
7
4
7
5
8
• If US is pricing at a
Europe
10
12
15
15
15
15
15
15
15
premium to resid – it
becomes the
advantaged market
0
2000*
2002
2004
2006
2008
2010
2012
2014
* Assuming end-of-year in-service dates. Regas projects shown only in operation and under construction. 47.6 Bcfd facilities approved by FERC. Liquefaction
assumes projects operating, under construction and in development. Includes Middle Eastern projects with expected delievries to Atlantic Basin based on
investing partners or signed contracts
15
Source: LNG Asian demand – Dr. Fesharaki, FACTS Inc., September 2005; McKinsey Energy Practice; McKinsey analysis