October 03, 2006 Oil & Gas: E&P
Investment conclusion
Lowering sector rating to 3-Negative. E&P companies are dealing with a combination of (1) weak industrial demand and (2) soaring costs. We recently outlined our view that extremely weak industrial demand is likely responsible for increase in injection rates and drop in nat. gas prices. Our new analysis implies E&Ps need roughly $12 gas to grow cash flow generation capability by 7%/year. Gap between likely prices and current costs lead us to downgrade group. See "Top of Cycle" note issued today for views regarding an out-of-control cost structure.
Summary
• E&Ps destroyed estimated 6% of stock-market value (ex. changes in valuation arising from changing oil and gas price expectations) in '06. Cash flow would need to be 65-70% greater than est'd 2006 cash flow to convince us that E&Ps grew shareholder value at 7% annual clip. This math implies E&Ps need nat. gas prices over $12/MMBtu to cover '06 costs.
• Despite 9% rise in est'd oil/gas revenues in '06 -- EPS fell avg of 8% in '06E and est'd CFPS rose 2% -- costs up est'd 20%.
• Average debt rose ($12 bil.), shares outstanding rose ($3 bil.) yet cash flow generation capacity of 15 large E&Ps did not increase (ex. prices) - implies $15 billion of shareholder value destruction before allowing for expected return.
• E&P companies need to slash budgets to rein in out-of-control costs. We think Q3 conference calls will lead investors to question the ability of E&Ps to fund '07 drilling plans; and this could lead to reductions in '07 production forecasts.
• We believe that the massive industrial demand destruction that has occurred over the past few years will become apparent now that peak air-conditioning load is behind us.
• If there are fewer "price-elastic" customers willing to step up and use more gas, we believe it will mean that we need to fix the supply imbalance by cutting production and we estimate this will be a slow (9-18 month) process.
• Cutting full-year '06 gas price estimate from $7.50/MMBtu to $7.00/MMBtu and '06 oil-price est. from $70/bbl to $67.50/bbl. Also cutting '07 nat. gas forecast by $0.50 to $7.50. Maintaining our $60/bbl oil estimate.
• Q3 asset write-downs could add to negative sentiment. Although market reaction has been muted in past write-down’s, full-cost ceiling test write downs could add to negative sentiment. APC APA DVN NFX are subject to full-cost ceiling test; while CNQ and ECA may need to disclose in US GAAP footnote.
• We believe that PXD, PPP and ECA may be most challenged to deliver results due to combo of cost structures and time lag between spending and expected production.
• Most gas-levered names include APC, NFX, ECA, PPP, XTO and EOG ($1 change in long term gas expectations should mean 9-13% to shares); while OXY, APA and TLM are least exposed .
• We estimate that 4 companies we cover will report 2H'06/'07 hedge gains of more than $100 mm at our new price deck. These include XTO EOG NFX and CHK (which is covered by J Robertson). We advise against overly relying on adept hedges when making investment decisions.
• We continue to believe that NBL and DVN will outperform peers. upgrading APA to reflect view that APA's broad geographic diversification will allow APA to outperform peers.
• We would avoid shares of PPP PXD APC and NFX for near term performance.
• In Canada we would rather own CNQ than ECA.
Summary
Problem #1. Cost Structure
We estimate that E&P companies destroyed about 6% of their stock market value in 2006. See "Top of Cycle" issued today for views regarding an out-of-control cost structure. We summarize the elements of value creation that we measured for 15 large E&Ps as follows:
• Enterprise value should have risen as a result of a 5% increase in overall oil and gas production. We estimate the value of increased production at current valuations of about $60,000 boepd, or about +$16 bil
• The value decrease resulting from rising cash costs is estimated at -$16 bil -- equals 6 times the increase in cash operating costs
• The portion of enterprise value owned by beginning shareholders was reduced by a $15 bil. Increase in average debt and equity in 2006 vs. 2005. This value creation metric is about $34 billion short of earning a 7% return on stock market value - that is more than 60% of 2006 cash flow earned in a $65-70/bbl and $7.00-7.50/MMBtu environment. Some may argue we should award the companies some credit for increased oil and gas prices over time. If we dial in a 4-5% expected price increase, the shortfall is cut in half. Capital and operating costs are out of control as companies drill aggressively while claiming economics are strong. Issue: Bottoms up drilling math looks so attractive – how can corporate returns look so poor? This is an issue we have struggled to understand – if companies claim go-forward drilling returns of 30%, 50% and even 100%, how can corporate returns be so poor?
• Go-forward lease level drilling returns explicitly ignore sunk costs (not only acreage and seismic costs but also overheads and the costs of drilling abandoned prospects well as early high-cost wells in new plays that companies use to optimize drilling and/or completion techniques). We believe that the leakage can be on the order of 30% (that implies that a 45% lease level return translates into a 15% corporate return).
• Many long-lived gas plays deliver the majority of production value in the first few years – yet production and reserve recovery continues for a long, long time. We ran an example for a non-conventional well and this led us to estimate that the first 50% of production can contribute 75% of the net present value (NPV) and the first 75% of production accounted for more than 90% of NPV. Perhaps we should assign the capital costs according to value returned and assign a finding cost of $4.00-4.50/mcfe to the valuable reserves (rather than reported numbers near $3) as a starting point in our economic analysis. Under this calculation the Henry Hub natural gas price required to earn an adequate rate-of-return may need to be the sum of (1) up to $4.00-$4.50 to recover capital spent, (2) about the same $4.00-4.50 to earn a return on that capital, (3) another $2.00-2.50 for cash costs and (4) +/- $1 for differentials. This would imply a required Henry Hub natural gas price of $11-12.50 to earn an adequate return on a finding and development cost of $3/mcf.
Problem # 2. Natural Gas Demand
A dramatic structural shift in natural gas demand patterns has masked the enormous decline in natural gas usage for at least the past two years. Electric power usage of gas rose 21% -- or 5.6 bcfpd -- in July to 32.7 bcfpd. The 2 summers were about equally hot. This 5.6 bcfpd increase in power demand more than accounted for a 2-3 bcfpd slowdown in injection rates vs. 5-year averages. Rising supply and/or falling industrial demand account for the 3 bcfpd gap. Increased reliance on gas to meet peak air conditioning requirements will continue for at least the next several years until significant new coal-fired capacity becomes available. Summer gas usage was much stronger than in past years due peak air conditioning, but year-round industrial demand has evaporated -- down 5-6% in the past 2 years and down nearly 30% from its 1997 peak. There is plenty more industrial demand that is vulnerable if gas prices stay high or as capital projects (energy conservation projects or projects that move gas-intensive consumers overseas) that are in the pipeline get completed (they will). Industrial demand was still the largest sector at 36% of gas demand in 2005.
Now that the peak summer demand season – along with structurally higher peak air conditioning demand for natural gas is behind us -- the storage overhang is again expanding. The storage overhang has risen from to 320 bcf 4 weeks ago to 354 bcf. We will likely end the refill season (November 3) at record levels, with an overhang of 300-400 bcf. That excess gas could be more than enough to meet requirements even if the winter is cold. Weak industrial demand, along with flat to rising US production, is likely to exacerbate the oversupply situation.
The Solution: Price Signals Could Be Telling Producers to: (1) Lower Costs and (2) Decrease Supply
Natural gas prices of $4-6/MMBtu in the recent past have not provided sufficient incentives for gas-consuming customers to help work off the overhang in storage. We expect that the supply-demand imbalance will need to be corrected on the supply side. We believe that E&P companies need to lower drilling budgets. A combination of terrible returns in 2006 and falling cash flows are likely to provide the impetus to budget disappointments.
• Capital spending cuts may be signaled on Q3 conference calls. We think that companies will likely provide hints, or that investors will deduce, that cash flow estimates are inadequate to fund aggressive increases in 2007 spending
• 2007 production growth forecasts are likely to moderate over the next 90 days as the market realizes that the companies cannot spend enough money to grow production.
• Production can react quickly if activity is reduced -- but activity needs to slow first. If indeed 30% annual production declines are the norm, the self-corrective mechanism can be quick. A 20% cut in drilling activity would likely lower supply by 1-2 bcfpd within 12 months. A production decrease of this magnitude (2-4%) would be similar to the experience in 2002 when yearover- year production fell 3-4%.
• Overall per-unit costs need to come down – If average energy prices had not risen in 2006 (we estimate that price realizations rose more than 10% to about $46/BOE in 2006) cash flow per share would likely have decreased on average. As a matter of fact cash flows per share rose an average of 2% in 2006 – even after allowing for a 9% change in unit revenues. Companies were unable to grow cash flow per share in 2006 and they need to find a way to finance cash flow per share growth from internally. We expect (1) a “high-grading” process where companies forego drilling their least economic wells; (2) decreased investment in new acreage; (3) decreased spending on areas where economic returns are uncertain and in any case may be years away.
Company Recommendations
While we are lowering our overall sector recommendation, we believe that there are both better and worse places to be invested in the group. Our top picks are NBL, DVN, APA and CNQ. While we retain 1-OW ratings on EOG and XTO, we are concerned that the high gas leverage may cause those shares to lag a bit in the near term despite attractive natural gas hedges (especially in the case of XTO). We retain a 1-OW on TLM as well, but we are concerned that Q3 production is likely to disappoint as a result of UK North Sea and other shortterm issues.
• 3-UW. Believe that PXD, PPP and ECA may be most challenged to deliver results due to combination of cost structures and time lag between spending and expect production. We rate each of these stocks 3-UW.
• Near-term risks. In addition to the 3-UW rated shares, we would suggest that investors looking for near term performance also avoid APC and NFX. APC because of its need to sell assets to raise cash – lower gas prices are likely to negatively impact proceeds for producing assets. NFX because of its aggressive capital spending plans
• The most gas-levered names, in our view, include APC, NFX, ECA, PPP, XTO and EOG ($1 change in long term gas expectations should mean 9-13% to shares); while OXY, APA and TLM appear least exposed
• Don’t count on hedges for too much protenction. We estimate that 4 companies among the larger producers will report 2H'06/'07 hedge gains of more than $100 mm at our new price deck. These include XTO and CHK (covered by J Robertson) which should report material gains of more than $1 billion each if our oil and gas forecasts are correct, as well as EOG and NFX which should report modest gains. We advise against overly relying on simple metrics that look at how much gas or oil is hedged. It is worth noting that 8 of the 13 large companies with price protection in place for 2007 have protection at prices that average less than $7/MMBtu.
• Upgrading APA to 1-OW to reflect view that APA’s broad geographic diversification should allow APA to outperform peers. The big win in our view would be if APA would sharply reduce North America spending and use the extra cash to either reduce debt (more likely) or to increase its previously announced $1 billion share buyback authorization (less likely).
• Canada swap idea. In Canada we would rather own CNQ than ECA. The risk an investor runs in shorting ECA is that the company appears likely to announce an upgrading agreement for its oil sands operations in the next 2-3 weeks. ECA’s plan is for bitumen production (SAGD) production to reach 500,000 bpd over the next 12 years – a processing arrangement would reduce the volatility of ECAs returns and perhaps cause investors to place more value on its oil sands (SAGD) assets.
