Credit Suisse E&P - Lower NG price outlook (Sept 17, 2010) | UPL Message Board Posts

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Msg  32048 of 38140  at  9/21/2010 3:00:00 PM  by

bobw02053


Credit Suisse E&P - Lower NG price outlook (Sept 17, 2010)

 

Credit Suisse – O&G E&P  - Sept 17, 2010

 

Lower Natural Gas Price Outlook

 

Lowering Natural Gas Outlook. We are lowering our 2011 U.S. NYMEX

natural gas price forecast to $5.25 per MMBtu ($5.00 in 1H10 and $5.50 in

2H10) from $6.00 per MMBtu. We are also initiating a 2012 forecast of $6.00

and we think gas markets can gradually improve on an expected reduction in

dry gas drilling as the industry reacts to conserve capital amid weak gas

prices. Our long-term price forecast of $6.50 starting in 2013 remains

unchanged and is based on a step change in gas demand related to organic

growth and coal displacement for this reasonably priced and available fuel.

We are also upgrading EOG Resources (EOG) to Neutral from

Underperform and updating target prices for E&Ps under coverage.

 

Short-Term Gas Markets Weak on Over-Investment. Near-term gas

markets are likely to remain weak on persistently high supply brought on by:

1) A record high horizontal rig count (up 60% in 2010) which adds

supply at 3x+ the rate of traditional vertical drilling,

2) continued investment beyond internally generated cash flow (166%

reinvestment rate in 2010 for gas producers) helped by hospitable

equity and high yield markets and cash infusions from JVs with

large international companies, and

3) aggressive lease capture strategies which is forcing low rate of

return drilling (‘use it or lose it’).

 

Revisions to Short and Medium-Term Oil Prices

We are also lowering our short and medium-term oil price forecasts with 3Q10 falling to

$76 per Bbl from $80 per Bbl and 4Q10 falling to $75 per Bbl from $80 per Bbl previously

(see “Fuel for Thought: Range-Bound Oil Prices for Longer” published 9/17/2010). Our

2011 oil price forecast falls to $72.50 per Bbl ($70 per Bbl in 1H11 and $75 per Bbl in

2H11) from $80, while our long-term oil price forecast remains at $80 per Bbl. Due to the

macro changes, EPS for 2010 falls 5%, EPS for 2011 falls 20% and EPS for 2012 falls 9%.

 

Maintain $6.50 Long-Term on Cash Flows Needed for Demand Growth

We are maintaining our long-term NYMEX natural gas forecast of $6.50 per MMBtu but

defer the normalized period to start in 2013 versus 2012 prior. As noted earlier, our 2012

forecast is now reduced to $6.00 per MMBtu. Despite the recent secular downshift in the

U.S. cost curve due to the exploitation of low-cost shale gas, we are optimistic on longterm

demand trends. We see rising demand from the electric power sector which we

estimate will call on an additional 6.0 Bcf/d by 2015, marking a fresh source of secular

growth for U.S. gas. Our $6.50 long-term price is also premised on the cash flows required

to supply this forecasted upswing in demand.

 

We Like Gassy Producers with Liquids-Focused Growth

The stock market has gotten the message that oil is a higher margin product and has

responded accordingly. In fact, oil focused producers have outperformed gassy peers by

23% since the beginning of 2010 and 30% since 6/30/2009. We see a better opportunity

today in companies that produce mostly gas, but are drilling few gas wells because they

have the liquids-prone assets in place to exploit. Likewise, we would highlight other ‘liquids

transition stories’ like Forest Oil (FST) and Newfield Exploration (NFX), which have a

significant amount of base gas production but future growth is primarily centered around

oil and NGLs with limited lease holding obligations. That should drive above average

multiple compression in the coming years. Also, FST has a fairly low-profile 102k net acre

position largely in the oil window of the Eagle Ford for which we are adding $4 per share of

value today.

 

 

EPS and Target Price Changes

We are revising our 2010, 2011 and 2012 EPS estimates based on our lower natural gas

and oil price forecasts and actual 3Q10 natural gas prices as well updated assumptions on

production, costs and basis differentials. Our natural gas outlook is now $4.72 per MMBtu

for 2010 (from $4.74 per MMBtu), $5.25 for 2011 (from $6.00) and $6.00 for 2012

(previously applied long-term gas price forecast of $6.50 to 2012). Our oil price forecast is

now $76.98 per Bbl for 2010 (from $79.23 per Bbl) and $72.50 for 2011 (from $80

previously). As shown in Exhibit 10 through Exhibit 12, our 2010 EPS estimates fall 5%,

our 2011 EPS estimates fall 20% while our 2012 EPS estimates fall 9%. Relative to

consensus, we are 4% below the street in 2010, 23% below the street in 2011 and 11%

below the street in 2012.

 

Along with EPS changes, we have also made revisions to our Risked (‘PD-Plus’) NAVs,

which have fallen 2% as a result of our changes in our commodity price outlook and

operating assumptions. Our NAV and target price revisions are shown in Exhibit 9.

 

Valuation

Producers Trading at 17% Discount to Risked NAV

Producers are currently trading at a 17% discount to our ‘PD-Plus’ NAV at our price deck

($80 oil and $6.50 gas long-term) with gas-focused producers trading at a 19% discount

and oily producers trading at a 14% discount. At the strip, producers are trading at a

smaller 13% discount with gassy producers trading at a 8% discount while oily producers

are trading at a much wider 21% discount. Please see Exhibit 13 and Exhibit 14.

 

Valuations Compress by 2012

On EV to 2011 unhedged EBITDA multiples, the group is trading at 7.3x at strip prices of

$81.16 oil and $4.68 gas with gas-focused E&Ps trading at 7.8x and oil-focused producers

trading at 6.6x. Valuations continue to compress as we look at 2012 at the strip with the

group trading at 5.2x. Gassy producers are trading at 5.7x while oil-focused producers are

trading at a lower 4.9x. Please see Exhibits 15 and 16 as well as Exhibits 52-57 in the

Appendix for a summary of valuation multiples

 

Natural Gas: Ready to Supply

Maintain $6.50 Long-Term on Cash Flows Needed for Demand Growth

We are maintaining our long-term NYMEX natural gas forecast of $6.50 per MMBtu but

defer the normalized period to start in 2013 versus 2012 prior. As noted earlier, our 2012

forecast is now reduced to $6.00 per MMBtu. Despite the recent secular downshift in the

U.S. cost curve due to the exploitation of low-cost shale gas, we are optimistic on long term

demand trends. We see rising demand from the electric power sector which we

estimate will call on an additional 6.0 Bcf/d by 2015, marking a fresh source of secular

growth for U.S. gas. Our $6.50 long-term price is also premised on the cash flows required

to supply this forecasted upswing in demand.

 

Onshore U.S. is Ready to Supply Coming Demand Growth

Recent trends have indeed demonstrated the market is capable of adding supply at sub

$5.00 per MMBtu gas prices with June 2010 production up 4.4% yr/yr or 2.5 Bcf/d despite

a 3.6% yr/yr decline in the 12-mo gas strip. However, the production gains have come

because of investment well beyond cash flows. Shale gas production has risen to 20% of

total onshore U.S. output from just 4% five years ago.

 

So Why are We Holding at $6.50 Long-Term?

That is because we believe this recent growth spurt has been subsidized by capital

infusions from joint ventures, asset sales and capital raises (more recently debt) amid an

industry disregard for full-cycle returns (instead favoring growth). The continued pursuit of

reserve growth and building unbooked locations (inventory) has trumped the importance of

project returns. Our $6.50 per MMBtu normalized forecast is instead based on the price

need to fund supply growth (read on).

 

Cash Flows Trump the Cost Curve in our Long-Term Outlook

Our extensive basin-by-basin return analysis results in a production weighted break-even

natural gas price below $6.00 per MMBtu. However, we believe that a cash flow backed

analysis is more appropriate for gas given significant reinvestment needs and legacy cost

structures that are above the incremental (not marginal) unit cost of production. As shown

in Exhibit 17, we have assessed the capital required to meet our demand outlook by 2015.

We model demand to increase 6.0 Bcf/d by 2015 or ~2.0% per annum and assume this

growth is fully met by domestic supply.

Based on a 130% reserve replacement rate per annum and unit future development costs

(average $2.10 per Mcf over the forecast period), we calculate the capex required per

annum to deliver the implied proved reserve growth (~2.4% per annum). We then assume

a 100% reinvestment rate each year to assess cash flow needed before working back up

through the income statement to solve for the required NYMEX natural gas price per year.

The analysis concludes that gas prices of $6.00 per MMBtu in 2012, $6.15 in 2013, $6.27

in 2014 and $6.40 in 2015 are needed to equate capex with operating cash flow.

 

Demand Outlook Should Strengthen with Lower Cost Gas, Emission Standards

Despite current natural gas prices in the $4.05 per MMBtu range and over 55% of the 980

strong gas rig count drilling in the low-cost shales, we are sticking to our constructive

stance on long-term gas prices. We believe electric power demand can serve as a fresh

source of secular growth in the medium term. We see clear advantages for gas as a 1)

domestic, 2) reasonably priced (versus coal), 3) cleaner (50% vs. coal) and 4) safer (from

an operational standpoint) fuel. We are using 3% demand growth in 2011 before rising to

8% per annum in 2012 through 2015. As noted, much of this growth is premised on the

shift to cleaner gas-fired power generation from coal burn.

 

We see room for even more demand late decade should a positive 1Q11 EPA ruling

restrict Mercury emissions (by 90% by 2015 from current levels). This follows the Clean Air

Transport Rule (CATR) put forth in July 2010 which also benefits gas over coal-fired

generation. In the meantime, our Power team estimates a potential 4.0 Bcf/d of

incremental demand from gas-fired generation should 50% of the unscrubbed coal-fired

fleet be retired by 2017.

 

Unlike the Past, Natural Gas Deliverability is More Reliable

Natural gas demand has been basically flat in the 22.0-23.0 Tcf range since 2001 (latest

available data) given modest cyclical growth offset by price elastic industrial demand in

recent years. But, price volatility has been extreme through most of this period amid

consistent difficulties in maintaining deliverability of supply. Merchant generators were

badly burned on their $2.00 per MMBtu gas bet in the early 2000's.

 

Gas has been seen as unreliable. But times have changed with the identification of

massive low cost shale reserves (read on) that can be reliably brought to the market at $5

per MMBtu, a sharp discount to oil products ($11.91 per MMBtu) and even coal (CAPP

spot at $5.35 per MMBtu equivalent currently). In fact, out year gas prices are ~$0.55-1.15

per MMBtu below coal through 2013 (see Exhibit 19).

 

Shales Driving Costs Lower

As illustrated in Exhibit 20, we have constructed a lower 48 cost curve based on the

weighted average of forecasted production from the Big 5 Shales (Barnett, Fayetteville,

Haynesville, Marcellus, Woodford) and assumptions on conventional decline rates. The

costs used in the curve equate our basin break-even prices needed to generate a 15%

after-tax rate of return for the incremental production added per year (~13.5 Bcf/d per

year).

For the remaining productive base that declines at 25% per annum, we assume a ~$1.75-

2.00 per Mcf cash cost. We project this cost curve falls from ~$5.66 per MMBtu in 2010 to

~$5.20 by mid-decade. Factors that would drive the market to deviate from this cost curve

would include 1) demand trends (e.g. our positive forecast), 2) industry ability to reinvest at

prices below $6.00 per MMBtu gas, 3) capital raises for reinvestment, 4) field-reservoir

degradation over time and 5) the role of Big Oil in U.S. gas as that would increase the

investable capex base.

 

‘Big 5’ Shales to Reach 40% of U.S. Supply

As shown in Exhibit 21, we project the big 5 shales to compose 19% of the market in 2010

but rise to 37% of the mix in 2015. Conventional production is forecast to fall from 38% of

the mix in 2010 to 26% in 2015 as the incremental unit of demand is likely to be met by

lower cost shale gas.

 

U.S. Natural Gas Resources Run Deep

With some 250+ Tcf of proved reserves and an additional 1,836 Tcf of unproved resources

(348+ billion Boe for total resources), U.S. natural gas has respective reserve lives of 11.6

and 84.8 years based on current dry gas production. This vast resource should prompt the

Administration and industry to consider greater usage of clean, lower-risk and affordable

natural gas. We recognize near-term demand trends are likely to remain weak, but the

potential for the beginning of secular demand growth in the coming years underpins our

normalized forecast of $6.50 per MMBtu. Please see Exhibit 23 and Exhibit 24.

 

Gas was a Just in Time Fuel…

Production trends since 2008 have proven the ability for natural gas to serve the market at

competitive prices (compared to coal and petroleum products). Building out demand

markets (power, transport) is the next step. End users have historically perceived natural

gas as a “just in time” fuel with little supply security and availability. That view was

primarily due to the exploration intensity of conventional gas and the volatility of production

and prices.

…But Deliverability Concerns Being Washed Away by Shale Revolution

However, end users should now find increasing comfort in supply security given the low risk

manufacturing nature of unconventional gas. Our basin analysis confirms the U.S. has

an extensive inventory of lower-cost gas resources (perhaps 50 to 90 years!). As

measured by the EIA-914 report, onshore natural gas production hit a record high in

March 2010 and as of June 2010 was up 4.4% yr/yr (2.5 Bcf/d) and up 6.2% (3.4 Bcf/d)

versus June 2008 levels. Production from the Big 5 Shales (Barnett, Fayetteville,

Woodford, Haynesville, Marcellus) was likewise up 30% yr/yr (1.7 Bcf/d) in 2009 and up

six-fold (6.2 Bcf/d) since 2005. Please see Exhibit 25 and Exhibit 26.

 

Economics Improving on Efficiencies and Completion Technology

The E&Ps continue to build on the sweeping productivity gains witnessed in 2009. It is

clear that every dollar is recovering more gas through the use of longer-laterals in

horizontal drilling and a related increase in the number of frac stages. The intensity of the

completion job (i.e. more and stronger proppant) is also driving productivity. Drilling days

also continue to fall (~20-30% versus late 2008), which is enabling producers to meet

volume targets with fewer rigs. An increasing emphasis on micro-seismic, frac-targeting

and spacing is also yielding better productivity and optimizing recovery rates (spacing).

Meanwhile, restricted rate practices (e.g. Haynesville) are reducing immediate growth

rates, but aiding long-term growth through softer decline rates and higher ultimate

recoveries (EURs).

 

Many Plays Now Break-Even Below $6 Gas

We have revised our basin economics analysis to show NYMEX natural gas prices

needed to generate a 15% after-tax rate of return. Our analysis also incorporates recent

changes in well costs and reserve recoveries by basin. As illustrated in Exhibit 27, most

natural gas basins ‘break-even’ at NYMEX prices below $6.00 per MMBtu gas. In fact, just

4 of the 22 basins in our analysis require $6.00+ per MMBtu gas prices to break-even.

 

Lower Cost Shales ~20% of Current Onshore Production

We now estimate the major shale plays will break-even at sub ~$5.25 per MMBtu NYMEX,

but they represent ~20% of lower 48 onshore current production and will take several

years to affect the overall cost curve. We would expect these shale breakeven prices to

rise over time due to secular inflation on the completion side (pressure pumping) and field reservoir

degradation. Also, we think that an improving demand backdrop will force some

level of higher cost conventional production to always be drilled. These are several factors

apart from demand that support our $6.50 per MMBtu normalized forecast.

 

Returns vs. Cash Flow

We think it is important to make the distinction between gas prices needed to make a

hurdle return on a well versus those needed to both maintain and grow existing production.

 

At gas prices below $6.50 per MMBtu, we don’t see sufficient industry cash flows for

reinvestment into such shale plays after considering maintenance capex. At the current

2011 strip, we estimate the gas-focused producers are spending 160% of hedged cash

flow. Furthermore, producer income statement cash cost structures are running $3.30 per

Mcfe, which would leave ~$2.00 per Mcfe margin at $5.25 per MMBtu NYMEX. This

margin appears too thin to both maintain and grow volumes when considering industry

future development costs are running $2.10 per Mcfe. In recent years, capital market

financing, asset sales and ‘carried’ joint ventures have helped bridge the spending gap to

achieve growth, but our normalized outlook reflects an internally funded market.

 

LNG Imports Unlikely to Impact the U.S. Natural Gas Cost Curve

We continue to see the U.S. natural gas market being self sufficient amid the discovery of

low-cost unconventional gas. LNG was historically viewed as vital for filling a future

domestic natural gas supply-demand gap. This view prompted the construction of 14.7

Bcf/d of regasification capacity in the U.S., with dozens of more projects in the pipeline.

But the emergence of onshore unconventional gas have reduced the U.S.’ need for LNG.

In fact, only 10% (1.4 Bcf/d) of regasification capacity is being utilized today as global

markets in Asia and Europe continue to offer a more competitive price (given oil-linked

contracts). Landed prices in the U.S. are running $4.09 per MMBtu (Henry Hub) which is

well below U.K NBP and continental Europe prices of ~$6.60 per MMBtu and Asia markets

that are likely bidding $8.50+ per MMBtu.

 

Liquefaction Line Up is Dwindling, But U.S. Won’t Compete

Global liquefaction capacity has risen 35% or 9.1 Bcf/d since the end of 2007, with the

largest increases coming in 2009 (6.0 Bcf/d). Global demand has absorbed most of the

new capacity, but facility maintenance, downtime and delays also helped the global gas

market avert a slump. Looking ahead, we see global liquefaction capacity rising another

7% or 2.4 Bcf/d in 2010 (bringing global capacity to 37.4 Bcf/d) before slowing to just 0.6

Bcf/d and 0.7 Bcf/d of planned adds in 2011 and 2012, respectively. See Exhibit 32.

Global gas markets could likewise tighten in the post 2011 timeframe particularly if global

gas demand growth recovers to a trend 2% (~6 Bcf/d per annum). However, we believe

the availability of low-cost domestic resources will keep U.S. prices uncompetitive relative

to global markets. Note LNG imports to date have averaged just 1.4 Bcf/d with recent

facility sendouts just below 1.0 Bcf/d.

 

2011 Natural Gas Market Analysis

Drilling Activity Remains High, Keeping Supply Strong

Despite a 27% decline in the front-month natural gas price and a 26% decline in the 2011

curve from the beginning of the year, the natural gas rig count has surged since the

beginning of the year, rising 221 rigs or 29% to 980 rigs while the horizontal rig count is up

340 rigs or 60% to 911 rigs. In fact, we estimate that the productivity-adjusted rig count

(including both oil and gas) is at an all-time high (see Exhibit 35). Activity remains strong

as producers continue to fulfill lease holding drilling obligations in the Haynesville (most

leases entered in 2008) and the Eagle Ford (most leases entered in 2009 and 2010). With

capital markets offering cheap liquidity and drilling carries driving more and more

production (read on), we think drilling activity will remain strong and should hold production

flat through much of 2011.

 

High Reinvestment Rate Driving Gas Growth

As producers look to maintain production guidance set forth during 2010 and retain

acreage, capital discipline has taken a backseat as producers are set to spend 143% of

hedged cash flow and 163% of unhedged cash flow in 2010 at strip prices. The capex to

cash flow imbalance is expected to remain in 2011 as we estimate producers to spend

141% of hedged cash flow and 154% of unhedged cash flow at strip prices, but does

improve yr/yr despite hedges rolling off as producer cash flow is expected to rise yr/yr on

the back the strong production.

 

Gas Hedge Roll Offs Not that Impactful

As shown in Exhibit 36 and Exhibit 37, hedge positions on North American gas are set to

fall from 52% in 2010 to 30% in 2011. The 30% level for 2011 is lighter than the 40% seen

one-year ago for 2010 as a fast falling curve had prohibited more hedging this summer.

We suspect producers are eagerly awaiting a winter rally to layer on additional protection

for 2011. While hedge positions indeed roll lower in 2011, the restraining impact on cash

flows is offset by asset growth and higher yr/yr commodity prices. Exhibit 41 illustrates that

we estimate hedge gains to fall from $6.4B in 2010 to $2.7B in 2011, marking a reduction

of $3.7B. Assuming $12.0k per Mcfe/d of capital productivity implies a production loss of

0.3 Bcf/d tied to that lost cash flow (or just 0.5% of lower 48 production). Cash flows

likewise for the group are forecast to rise 19% yr/yr or by $11.2B to $66.5B despite the

“roll off” effect.

 

Drilling Activity Sustained by Easy Money, JV Agreements

While most drilling offers low returns at current price levels given the recent increase in

completion costs, producers are able to maintain high levels of activity as the capital

markets have offered virtually unlimited capital for producers to restore liquidity and term

out debt. To date, the E&Ps have raised $27.5B ($17.1B of debt, $6.5B of equity and

$3.9B of preferred, see Exhibit 42), which already exceeds last years total of $25.4B (see

Exhibit 43). Most financing costs have been attractive at rates ranging from 5-8%. Further

contributing to available drilling capital are JV proceeds and drilling carries received over

the past several years, which we estimate total $7.5B in 2010 alone and $17.5B since

2008. The drilling carries in some cases allow producers to drill with F&D costs essentially zero as the JV partner (typically a Major or NOC) funds a majority of the producers drilling

capital.

 

Supply/Demand Factors Indicate Tighter Market in 2011

We have initiated supply/demand estimates for 2011, which show the market to be tighter

on a yr/yr basis. As seen in Exhibit 44, we are forecasting 2011 to be 0.4 Bcf/d tighter yr/yr

on stronger demand from the electric power sector as gas continues to trade well below

coal on the futures curve while we also see some additional gains possible in industrial

demand. We also expect further tightness in offshore volumes as declines are likely to

continue as a result of the drilling moratorium as well as Canadian natural gas imports.

This tightness should be partially offset by yr/yr gains in onshore supply given the increase

in the natural gas rig count and as producers have shifted to more efficient horizontal rigs

throughout 2010 as well as higher LNG imports with the startup of the Golden Pass facility

shortly.

Specifically, our supply/demand factors for 2011 show:

Onshore U.S.: 0.5 Bcf/d looser yr/yr

Offshore U.S.: 0.3 Bcf/d tighter yr/yr

LNG Imports: 0.2 Bcf/d looser yr/yr

Canadian Imports: 0.2 Bcf/d tighter yr/yr

Demand: 0.6 Bcf/d tighter yr/yr

Net: 0.4 Bcf/d tighter yr/yr

 

Onshore Supply Expected to Stabilize in 2H10 and 2011

After rising roughly 3 Bcf/d from the trough in 3Q09, we expect production to begin to

stabilize in the second half of 2010 and into 2011 as the growth in the rig count has begun

to slow with the limited availability of high horsepower rigs. While we see the natural gas

rig count beginning to decline in 2011 as Haynesville lease capture is largely completed,

production may not fall materially as producers move some to the Eagle Ford, which also

produces significant gas, and realize ‘pad-drilling’ efficiencies as the Haynesville enters

manufacturing mode.

 

Industrial and Electric Power Demand Expected to Further Improve in 2011

We expect to see further improvement in industrial and electric power demand following

strong performance thus far in 2010 with industrial demand up 9.9% or 1.7 Bcf/d YTD and

electric power demand up 5.1% or 0.9 Bcf/d YTD. Industrial demand remains strong as

Steel Production Capacity Utilization is at 72.1%, up 25% yr/yr and 115% from the end of

2008 while U.S. Distillate Demand is up 11.5% yr/yr. We are forecasting industrial demand

to rise 0.1 Bcf/d yr/yr as a result of continued gains expected in U.S. industrial production.

We are forecasting a larger 0.5 Bcf/d increase in electric power demand given lower gas

prices relative to coal. As seen in Exhibit 49, the coal futures curve is trading well above

the natural gas futures curve, which should allow gas to continue to gain share.

 

Storage Forecasted to Exit 2010 Injection Season at 1.482 Tcf

Using our 2011 supply/demand analysis, we forecast storage levels at the end of the 2011

draw season (March 2011) to total 1.482 Tcf, 156 Bcf below the 2010 withdrawal season

end and 75 Bcf below the five-year average (see Exhibit 51 for a breakout of seasonending

storage scenarios). The storage overhang that plagued the market throughout

2009 has been completely eliminated as a result of a cold winter in late 2009 / early 2010

(HDDs up 4% vs. normal for December through February) and a hot summer in 2010

(CDDs up 24% vs. normal for May through August). We would also highlight that future

storage capacity concerns have been somewhat mitigated as the EIA recently increased

its working gas storage capacity estimate by 4% to 4.049 Tcf.



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