Dave's Energy

Honest Data on Tax Rates Paid by Millionaires

2012-01-26T09:22:00.000-08:00

OK, this isn't technically an energy topic, but...I am bothered by the way certain politicians mis-use tax data to attack "the wealthy", the latest target being Mitt Romney after his recent tax and income self-disclosures. President Obama recently said that he's not inciting "class warfare", he just wants millionaire's to "pay their fair share" of taxes and doesn't believe guys like Warren Buffet should have a lower tax rate than their secretaries. So, first off, let's recognize that neither Buffet's taxes, nor Romney's, represent the situation for most other wealthy tax-payers, and his secretary's pay isn't likely to bear much resemblance to the "average" middle class worker.

Secondly, let's work with real data, provided by the IRS, the most recent available is from 2009 tax year. Presented at the bottom of this post is a summary of all Federal Income Taxes paid by individuals in the U.S. for 2009 (click on the image to enlarge it so you can read the data). A few observations:

Out of 140.5 Million tax returns filed, there were only 236,883 tax returns in the U.S. with Adjusted Gross Income (before any deductions, exemptions, or credits) in excess of $1,000,000. That is roughly the population of Lincoln Nebraska or Fort Wayne Indiana.

Those 236,883 taxpayers represent just 0.2% (one fifth of one percent) of the taxpaying population, and they paid $177 BILLION of the $865 Billion in taxes collected by the IRS. That is 20.5% of all the taxes paid by individuals. After all deductions and exemptions, 86.2% of their AGI income was taxable, and the $177 Billion in taxes is 24.4% of the $726 Billion they earned. So, while Mitt Romney and Warren Buffet may have pad an effective tax rate of 14%, that is not the case for the average million-plus earning household, which paid at an average rate of 24.4% in 2009.

Go through the table data and notice the rate at which each income level pays taxes. Note things like the people at $1 - $1.5 million paying on average $303,026 to the IRS. Some in politics would have you believe these people get some great tax breaks...but note that same group has taxable income of $111 billion on AGI of $130 billion, so they are paying on 86% of their earnings. The same holds true for all earners above that level until you see a small break at the $10 million and above level (paying an effective tax rate of 22%, due no doubt in part to 15% tax rates on capital gains and certain dividends). So much for tax breaks!! Only 14% of their income gets shielded by any deductions at all.

The middle class, incomes between $50K and $1 million, comprise 33.7% of all tax returns filed, and they paid $627 BILLION in taxes on $5.2 TRILLION dollars in AGI, for an effective tax rate of 12.1%, what appears to be a reasonable rate. The rest of the country (the under $50K in income) pays only 7% of all taxes. Appropriately fair again, in my view...we should not be taxing low wage earners while also supporting with government programs....that is counter-productive. So, 93% of all taxes are paid by earners over $50K, including the highest million-plus earners, while the average tax rate under $50K is 3.5%, after deductions, exemptions, etc.

So, the millionaires are paying at twice the rate (24.4%) of the average middle class worker (12.1%) and seven times the rate of low-income earners. Those 236,883 taxpaying "millionaires" earned an average of $3.1 million in adjusted Gross Income and paid and average of $749,315 in Federal Taxes in 2009.

At a 24.4% effective rate, are the million-plus crowd paying their "fair share"? I would say so. Can they pay more? Maybe, but that isn't the argument made by politicians. If they want to raise taxes on the rich, maybe they should just do so and just call it what it is. This is why President Obama's statements are seen as "class warfare", because they manipulate data to make it sound as if the "rich" are getting away with something. Instead of creating divisiveness among our population, why don't you celebrate the successful, recognize their contribution, and then ask (ok, mandate) for more taxes to be paid. At least they wouldn't feel demonized while also being taxed at high rates.

Last point: given the proposal to increase the effective minimum tax rate to 30% for all income over $1 million, we should ask ourselves what results from that increase. If we take the aggregate taxable income for that group ($626.5 Billion) and increase the rate from the 24.4% they already pay to 30%, that increases total taxes collected (based on 2009 data) from $177 Billion to $218 Billion, a meaningful $40 Billion, or 23% increase in tax collections. For those 236,883 taxpayers, it's another $171,279 in annual taxes on their $3.1 million in AGI.

But wait: $40 Billion is meaningful to the overall individual taxes raised, but what about relative to our annual budget deficit? In fiscal 2010, the U.S. deficit was $1.7 TRILLION dollars (and growing). That is just one year's shortfall of expenses over income. So, $40 billion more would not even knock our annual deficit down to the next round number of $1.6 Trillion. Our problem isn't Federal income, it's Federal spending. Taken to the extreme, you can see that taxing million+ earners at 100% rate (that is, taking their entire $726.9 billion in AGI from them), still wouldn't even cut our annual deficit in half. We cannot tax our way out of this issue based on higher RATES of taxation. We need the entire economy to grow so that the rates we now charge are applied against a larger base. Politicians need to stop fanning the flames of discontent and instead should focus on what we need in this country: jobs, entrepreneurship, and growth.

2011-10-20T21:21:00.000-07:00

My Solar output has been staying fairly steady this year compared to 2010. My total solar output in 2010 was 9724 kwh or 26.64 kwh/day on average. Total electric usage on top of the Solar production is about 30 kwh per day in both 2010 and 2011. Given that my marginal rates for electricity above 30 kwh a day are $0.30 to $0.40 a kwh, I am saving about $3500 a year on my electricity bill. Given the net cost of my 7.3 KW system after incentives, my system will pay off in 9 years or less (less under the assumption that marginal rates will rise in future years).

My monthly 2010 solar electricity output looked like this (Jan was just a half month as that was when the system was turned on):

My monthly 2011 solar electricity output looked like this

Why I look for 200% Reserve Replacement in an E&P Investment

2011-10-18T09:54:00.000-07:00

One of the key things I have always looked for when evaluating an investment in an oil and gas exploration and production (E&P) company, is the ability to economically replace reserves at a rate of over 200% of annual production. That is, for every barrel a company produces, I want to be able to see that the cash flow generated from that production allows them to go find and replace that barrel with two more barrels (2 new barrels replacing one produced = 200% reserve replacement). Doing so with internally generated cash flow allows a company to grow reserves at a reasonable rate, benchmarking around 10%, without raising capital and diluting investors. Why, you may ask, does it take a 200% reserve replacement ratio to grow reserves just 10% annually? Some of you already know the answer, but let's run through an example.

Let me start with the simple example I've shared over the years. I'm simplifying here, but if you are a producer that can find a barrel (Bbl) of oil for $20, produce it for $10 and sell it for $50, you'd be pretty happy. This mathematical model allows for growth in reserves and production and a positive return on capital. First you should recall that an E&P company needs to at least replace each unit of oil it produces with a like unit, otherwise it is just depleting away it's existing asset base. Therefore, the sale of each unit must generate enough excess cash flow to go replace that unit at a cost equal or below that excess cash flow. Let's say your operating metrics look something like this:

1) Drilling and completion cost of your latest well: $6,000,000
2) Size of new reserve from this well: 300,000 Bbls
3) Finding cost per Bbl: $6,000,000 / 300,000 = $20.00 per Bbl
4) Producing life (expected reserve life) of well: 10 years (note that production is not linear, that it comes on at the highest rate it will acheive and will decline over time due to reservoir and pressure depletion)
5) Lease Operating Cost per unit (to flow it from well, maintain well ops, etc): $10.00 per Bbl
6) Sale price per Bbl: $50.00

Therefore, each unit produced will generate cash flow of $50.00 minus $10.00 in lease operating costs, or $40.00 per unit. But now you have depleted your asset base by 1 barrel, so what do you do? You take your $40.00 in cash flow and go invest it into a new drilling program. Since your finding costs are $20.00 per Bbl for a 300,000 Bbl well (assuming here you have a repeatable drilling program), you have the ability to replace your one unit produced with two more. Note that another way to look at it is that the $50 -$10 - $20 finding costs gives you excess of $20 which is "full cycle" free cash flow that allows you to create one new barrel through drilling. So don't be fooled by the $50 - $10 calculation, at first glance you might imagine I was ignoring finding costs. Full Cycle cash flow must be no less than zero to stay flat in reserves, or be positive to grow the company.

This is essentially how you grow the company. In this case above, your company would have the ability to replace reserves on a 2-to-1 basis. But note that producing one actual Bbl doesn't actually get you two because you don't drill wells that are just two Bbls in size. In the absence of borrowing money to drill, you actually need to produce enough of your existing reserve to get the money to drill the next well. In this case, you'd have to produce 150,000 Bbls (half your expected reserves for that well) before you had enough money to drill your next $6MM well…this might take a couple years. The sooner you get your cash back, the sooner you can drill your next well. This is why the first months and first year of production is important.

So let's assume you have 3 million barrel (3MM Bbls) of total reserves at the beginning of the example. You spent $60MM to develop those reserves and have total finding costs of $20.00 per Bbl, which are on your balance sheet as an asset. Your average reserve life is about 10 years, and for simplicity, lets say you are producing 300,000 Bbls each year (this assumes linear production and no decline but is not relevant for the example). You are therefore generating $40/Bbl in cash flow times 300,000 Bbls for $12,000,000 per year. You can use that to drill 2 new wells at $6MM each and come up with another 600,000 Bbls of new reserves. This would be considered a 200% reserve replacement ratio (600,000 Bbls new / 300,000 Bbls produced). But although you replaced 200% of what you produced, your underlying reserve base grew by just 10%:

3,000,000 Bbls beginning reserves
- 300,000 Bbls produced
+ 600,000 Bbls found
= 3,300,000 BBls ending reserves.

In this case, you grew your company's reserve base by 10% annually by achieving a 200% replacement ratio on production.

Of course, if you have a bad year and you spend $12MM in drilling costs and only find 300,000 Bbls of oil you find that your reserves did not grow at all. This is essentially the position many of the larger integrated companies find themselves in: it is very hard to grow reserves once you get to a certain size. The big guys tend to just replace production at a 100% rate, give or take a few percent. Those are not growth companies. Also note that industry-wide finding costs are likely to be in the $15-$20/Bbl range these days and anyone who can improve on that has a big growth advantage.

So…using the FASB 69 supplemental disclosures at the back of every public E&P 10-K:

1) look at annual finding costs (total capital expenditures for drilling / total change in reserves, adjusted for prior period changes)
2) Calculate operational cash flow per barrel produced (Rev - Op Cost) and full-cycle cash flow (Rev - Op Cost - Finding Cost). Compare Op Cash flow to Avg Finding Costs to determine CF per Bbl
3) Look at total reserve replacement (total new reserves / total production)
4) Compare across companies and over rolling 5-year periods (one year isn't a fair assessment period for a growing E&P company) and you will find significant differences that can lead you to asking the right questions about a company's value and ability to grow. Of course, history doesn't predict the future, but positive trends in a company's costs over time should tell you something about the type of reserves the company is chasing and how they are managing their growth. Consistent reserve replacement should be a sign of strength while highly volatile results may be cause for further investigation.

There are many nuances to these calculations which I won't go into here (for example, how to factor in annual reserve adjustments based on price changes and vs. technical reassessments, and the amount of PUD - Proven Undeveloped - reserves that any given company is booking along with their Proven reserves). Again, this example is intended to cover the basics for now. In a later post, I will show an example of the many inputs and calculations.

But now you should start to get pretty excited about a company that has finding costs of $10/Bbl, operating costs of $10/Bbl and is selling oil at $75+ per barrel. You will realize that the ability to grow reserves quickly and economically goes up exponentially when you have all the right cost structures and the ability to repeat drilling success in a given area. For those of you new to this, that is what the industry refers to a "resource" play…an area that has a known resource that can be accessed with existing techniques to result in known well outcomes that cluster around a statistical mean. Hence, the value of a Bakken oil well that I discussed in my earlier post becomes more important when repeatable with known economics. At the end of this year, when 10-Ks come out in April with audited reserve numbers, I believe we will see tremendous reserve growth in the Bakken players, with exceptional finding cost results and industry-leading economics.

What's a Bakken Shale well worth?

2011-10-04T10:43:00.000-07:00

In and around energy conferences and among energy guys I hang around with, this question will elicit various responses, partly because there is no "one" Bakken Shale type well. The Bakken play continues to expand and wells vary depending on whether you are asking about the Middle Bakken formation or the lower Three Forks/Sanish formation, and also whether you are talking about the core of Montrail County, ND or the fringe out near the Montana border or into Montana or Saskatchewan. However, for my friends who are not constantly crunching numbers across all these play types, and for the students I work with on understanding the sector, I thought I'd share a very basic model for evaluating the Net Present Value of a single Bakken well. I'll call this a core Middle Bakken well. Using this, with some adjustments when required, you can make conclusions about the value of various companies producing and exploring in the area.

Thanks to the fine people at companies like Continental Resources, Whiting Petroleum, Brigham Exploration, Northern Oil and Gas, Kodiak Oil & Gas, and Triangle Petroleum, as well as the North Dakota Industrial Commission's Oil and Gas website it is fairly easy to find information on the production history of wells drilled in the area.

Companies have discussed in many presentations and press releases wells with initial production rates of 500 barrels of oil per day (BOPD), or 1,000 bopd, or even 2,000-3,000 bopd. With ever changing horizontal drilling and multi-stage frac techniques, the numbers continue to evolve, but with hundreds to thousands of data points now available, we can simulate our own well "type curve" based on what we know of these many existing wells. For those new to the subject, apologies for some missing assumptions, but you should know first off that all these wells follow a pattern of very high initial production with production rates that decline at a decreasing rate. That is, the production per day looks like a falling curve that flattens out over time.

Based on known data in the Bakken region, I will use the following as basic assumptions:

1) Initial production rate of 1800 bopd (ignoring associated natural gas production)
2) Average 30 day production (first month) of 700 bopd
3) First year decline of 55% from initial sustained 30-day rate
4) Decreasing rate of production decline through year 7 to get to an exit rate of about 100 bopd
5) $6 million cost to drill and complete a well
6) Lease Operating expenses and production taxes totaling $20 per barrel to produce
7) Local Oil Price sales realization of $65 per barrel (this takes into account transport costs, etc)
8) Expected life of well: 11-15 years
9) Expected Ultimate Recovery (EUR) of oil: 700,000 barrels per well
10) Discount rate of 10%

The production "Type Curve" looks something like this, which is just a graphic representation of the amount of well produced on a per day basis through time:

Here's a simple spreadsheet you can build to calculate this all yourself, with inputs shown in blue and calculated cells shown in black. Once you have created the average production per day based on annual exit rates, you can calculate the annual production, then apply a net cash flow number (realized oil price less cash costs) to get an annual cash flow, then discount that back for each year (CF / (1 + R) raised to the number of years out). Click on the image below to see it more clearly:

Please note that a few items are simplified here. For example, the cost of production is assumed to be perfectly variable ($20/barrel), yet some production costs are fixed and therefore will be relatively higher on a per barrel basis as the well gets older. It turns out this isn't a huge impact on valuation, however. Also, the "stub end" of production is truncated here for simplicity (the years beyond year 10) but it turns out, again, that these are less important to value than what happens in the first 5 years.

Results and things to note:

A) The NPV of a well is about $15.7 million with IRR of 100%, even at $65 oil
B) The NPV is about $22 per barrel ($15.7 MM NPV/ 700,000 barrels EUR) , indicating what reserves might be worth on a company's books and definitely what they would be worth in an acquisition.
C) Payback is under 12 months (although most companies will conservatively tell you 18 months - this is due to a mix of wells that may produce less than this modeled well)
D) If you change oil price to $85, NPV goes to $25MM per well ($36 per barrel), with 159% IRR and 6-9 month payback on investment.
E) If you change oil price to $45, NPV goes to $6MM per well ($8 per barrel), with 43% IRR and 24-36 month payback on investment.

So now when a company tells you they have 100 core Bakken wells to drill, you can have a thumbnail idea of value: $600MM cost to drill all those wells, with NPV of $2.2 Billion. SO you ask yourself: How many acres does it take to have room for 100 wells? At two wells per 640-acre section, that would require a lease position of 32,000 acres. Not a huge position for most companies. This means a lot of value can be created in a small area. It is important to note that many believe the ultimate development of the Bakken will see 6 wells per section, so there is even more value in good acreage, and even a small area can potentially be very valuable.

So there ya go...fodder for your next cocktail party chat regarding the value of a Bakken shale oil well. Disclaimer: don't take my word for it, read the 10Ks and presentations of all the companies doing the hard work up there.

Hedge Accounting is Distorting the Reality of Oil and Gas Production Earnings

2011-05-13T09:50:00.000-07:00

Yes, it has been some time since I have posted anything. What can I say? Life is busy!

OK, I was trained as an undergraduate accounting major, so I understand as well as anyone the desire to match liabilities with the period in which they are incurred. However, the accounting methods for hedging under SFAS 133 (“Accounting for Derivative Instruments and Hedging Activities”) often seem to do more damage than good. Let me explain why this may be a great time to look again at some compelling small-cap exploration and production company stocks. I am writing this entry for the benefit of some of my friends who aren’t experts in oil and gas accounting (neither am I), so pardon the rudimentary lesson, but it is important for investors in this sector to understand.

What some investors see in the most recent quarter (Q1 2011) for small and mid-cap oil and gas producers are large negative net income numbers. Casual observers then ask: “How come these companies aren’t making tons of money in this high oil price environment”. Or: “If they can’t make money at $105 per barrel oil, when can they”? Some of these companies were punished in the stock market after their most recent quarterly results (which unfortunately also came at a point when NYMEX oil prices have been dropping from their highs). So, I will make two very basic statements to start off here:

1) Most of these companies did NOT lose money this quarter, and

2) You have not yet seen $100 per barrel oil hit the income statements of most of these companies

What actually happened is that commodity hedging, and the accounting thereof, has made it harder to see the true earnings of oil and gas producers. Rather than smoothing out earnings, hedge accounting can make earnings significantly more volatile, and moreover, completely misrepresents how an oil and gas company thinks about hedging its risk and managing its budget. Contrary to what we want, in a very volatile oil price market, companies that have locked in fixed prices actually appear MORE volatile than their unhedged comparables.

I will start with the basics, creating an example with my fictitious “Dave’s Oil Company” (DOC). DOC produces 200 barrels of oil a day, and has confidence that production will remain for the next couple of years. So in the latter half of 2010, as oil prices were rising to over $90 per barrel on the NYMEX futures “strip”, DOC decided to hedge some risk by entering into an oil swap with a large derivatives dealer, covering half its production, or 100 barrels per day. A swap basically is a contract that says DOC will pay the other party if oil is above that level and the other party will pay DOC if oil is below that level. That swap allowed DOC to guarantee that it would receive $90 per barrel for 2011 and 2012, regardless of whether oil prices went up or down. If oil goes to $80, the other party pays DOC $10, DOC sells the oil for the market price of $80 and they have received $90 all-in. If oil goes to $100, DOC pays the other party $10, sells its oil for the market rate of $100, and in the end has netted $90 per barrel.

So, DOC has done something great for its investors, its budgeting process, and its lenders and other partners. It has established a future price for a portion of its production and reduced a certain amount of price risk. Since they only hedged half of their production (100 barrels per day of their 200 barrels per day production), they still have some exposure to the upside and the downside, but their volatility is cut in half. If oil drops to $40 per barrel, they will get an average of $65 per barrel (100 barrels at $40 and 100 barrels at $90), and if oil goes to $130, they will receive an average of $110 per barrel (100 barrels at $130 and 100 barrels at $90). In a world where oil might range from $40 to $130, they will only range from $65 to $110.

Now Q1 of 2011 rolls around, and let’s say oil goes to about $110 per barrel by end of quarter. DOC is selling its oil on the open market for $110 and paying the other party in the swap $20. They are netting that expected $90 per barrel for half of their production, and happy to be getting the other half at high market price of $110. Their average realized price after hedging is $100. Total revenue for the quarter would be:

Revenue = 91 days in the quarter X 200 barrels per day X $100 per barrel = $1,820,000

And let’s assume for the moment that they have something like a 20% pre-tax margin.

Pretax Income = Revenue of $1,820,000 X 20% = $364,000

Less a 40% tax rate would give us Net Income of $218,400

With 100,000 shares outstanding, EPS is $2.18

As a shareholder, you’d be happy about your beloved DOC selling oil at $100. Although they gave up some upside with the hedge, everyone sleeps better at night and they can better manage their business.

But WAIT… hedge accounting changes what you see on that income statement. DOC has made a commitment to pay the swap counterparty through 2012. According to the accounting rules, DOC has to recognize this liability. Hedge accounting says DOC must calculate the total value of all those barrels that will be sold at $90. If oil prices on the futures exchange now say that oil will be $110 for the next two years, DOC has to show what that number is. With 365 days in 2012 and 274 days remaining in 2011, it would look like this:

100 barrels per day X 639 days X $20 per barrel = $1,278,000

DOC records a hedge liability on its books (either as a liability or as a change in other comprehensive income in the equity section) and the offsetting entry goes on the income statement. OUCH! They record a “Loss on Derivative Instruments”) above the tax line for $1.278,000. WOW. That wipes out all their net income for the quarter. Heck, it’s almost as big as their revenue line! Now you see this income statement instead:

Revenue: $1,820,000

Pre-Tax LOSS = <$914,000> (that’s the $364,000 “normal” income less the $1,278,000 loss)

After a 40% Tax benefit: Net Income (Loss) of <$548,400>

With 100,000 shares outstanding, EPS is negative <$5.48>

That is the headline number: “Dave’s Oil Company Losses $5.48 per share in First Quarter”

Oh, sure, the company press release then says “adjusting for non-cash hedge accounting losses, the company made $2.18 per share. But the damage is done at the headline level.

More importantly, did the company actually LOSE that $1.2 million? I contend they did not. They have lost the OPPORTUNITY to sell at that higher price in the future, but they made that decision for good reason.

Here’s the next step: When second quarter rolls around, DOC will sell its oil on the open market at the going rate, let’s say it is still high at $110 per barrel. At that point, they record revenue at the market price of $110, and reverse the portion of the liability associated with the current quarter, offset that with a charge against income in the income statement, and the net of it makes it look like they sold the hedged oil at $90 per barrel. That is a good thing…trying to make the income statement look like the reality. However, DOC could just as easily NEVER recorded the liability and would STILL be recording the $90 per barrel currently on an after-hedge basis in Q2. I contend we should use some sort of contingent liability recording in the footnotes of the statements, but that what was done in the old days, and post-Enron, nobody likes this treatment.

But here’s what makes the current method really bad and volatile: If oil prices DROP in Q2 (like they have in 2011), DOC will reverse a large portion of that liability. Let’s say oil goes to $100 across the futures strip, so now DOC will reverse roughly half of what they recorded previously (except that portion associated with the now-past Q2 2011). For simplicity’s sake, let’s say that is roughly $600,000. The Q2 income statement would look like this:

Revenue: $1,820,000

Pre-Tax GAIN = $914,000 (that’s the $364,000 “normal” income plus the $600,000 gain)

After a 40% Tax: Net Income of $548,400

With 100,000 shares outstanding, EPS is $5.48

So, now you see the volatility I spoke of: Instead of recording two consecutive quarters of $2.18 in earnings per share, the company has recorded a $5.48 per share loss followed by a $5.48 per share profit. It still looks, to the unaided eye, that the company has made ZERO profit for the first two quarters combined. And importantly: contrary to what we want, in a very volatile oil price market, companies that have locked in fixed prices for longer periods actually appear MORE volatile than their unhedged comparables. The price volatility “around” the hedge gets recorded every quarter and whipsaws a small company’s recorded profits (but not their cash flow…and that is why you should look at cash flow instead of earnings).

You may also see why I contend many E&P companies did not lose money in Q1 (and please note the vast difference between oil-focused companies and those that produce mainly natural gas). You should also see why I said you haven’t yet seen the impact of $100 oil on many companies. Many of them are living with older hedges that have kept them averaging more like $75 to $80 in Q1. As the older hedges come to fruition and are replaced by higher-priced barrels, you will ultimately see higher average oil prices on income statements. Maybe I will post a separate blog on that subject…

In any case, if oil prices stay just under $100 through Q2, you will see large reversals of those liabilities and losses from Q1, resulting in non-cash gains to be recorded in Q2. The headline numbers will look much more positive in Q2 (July and August reporting dates). There may be some good deals to be had right now in oil-focused small cap E&Ps with large, attractive, hedge positions.

But don’t be fooled: hedge accounting is making it hard to look at headlines and bottom lines. As always, value and truth is found in between the lines.

Energy companies pay the most taxes amongst the S&P500

2009-11-02T06:44:00.000-08:00

Total taxes paid for 2008 by the largest corporations in the U.S. (as represented by the S&P500) are shown in the table below. The Energy companies in the S&P500 earned 18.5% of the revenues in the group but paid 29.8% of the actual cash taxes paid in 2008. Financial firms paid less in aggregate but paid the highest rate compared to revenues (presumably due to fewer deductions such as depreciation, as the Financial sector is less hard-asset capital intensive). Energy companies paid at a rate twice that of many other industries. When this year is over, 2009 will likely be the same story, with energy companies being the largest corporate taxpayers in the country. The myth of big tax breaks for energy companies needs to be dispelled.

Source: Capital IQ, Company documents, SEC filings

The latest data from BP's Statistical Review of World Energy

2009-06-17T06:35:00.000-07:00

I know it has been a long while since I've posted, but things have been busy! Right now I am working on an analysis of European unconventional oil and gas opportunities, but I am also slogging through the latest data provided by BP in their annual "Statistical Review of World Energy 2009". This annual compilation of data and analysis is an industry standard and for those who haven't ever viewed this rich data source, it's time you check it out. Much of the macro data essential to understanding the fundamental energy supply and demand structure of the world is available here, including traditional and alternative sources of energy. Thanks to the team at BP, as they do an amazing job with their report each year, and they provide great tools for charting, manipulating, and downloading data. If you don't want to download and manipulate data yourself, the Energy Charting Tool is very user friendly. The more you get into it, the more you appreciate it.

I'll be back soon with some thoughts on European natural gas...

Energy Policy. First Step: Admit You Have a Problem

2008-04-29T22:02:00.001-07:00

I would like to propose two prerequisites for any political candidate:
#1) take at least one Economics Course
#2) Visit an AA meeting

As we continue to suffer the ridiculous rhetoric and glaring lack of economic understanding from our Presidential candidates on how to solve our energy issues, I am reminded that most alcoholics know how you start to fix an addiction. You first admit you have a problem. Our politicians haven't done so yet.

Instead, they want to blame everyone else: OPEC isn't producing enough; Big Oil is greedy, speculators are causing the problem; Detroit won't make the right cars; taxes are too low on energy producers (I love the stupidity of that one).

Back in the 1970's, my connection to the energy business was a modest one. I was a teenager working as a gas station attendant in California (before the days of "self-serve"). I have distinct memories of turning customers away during the days of gas rationing, which in California meant consumers could only buy gas every other day, based upon the last number (odd or even) of your license plate. I was 16 years old and I had the power to refuse service to people. Boy, did they hate that. People begged for just a gallon so they could get to work, school, etc. It was a terribly misguided energy policy, and it caused people to hoard gas, fill up more often, and even steal gas (people learned to siphon from other cars, and this led to the invention of something previously unseen: a locking gas cap).

That bad policy did nothing to help people during a shortage, and in fact probably exacerbated it, but what it did accomplish was that people started to admit they had a problem: an addiction to something with finite supply. At the same time, something very different than today was being discussed by our leaders... they actually said that oil would likely stay high in price and get worse over time. With oil at $30, they said it could go to $100! From our President (Jimmy Carter got on TV in his cardigan sweater and asked us to turn down our thermostats), to OPEC leaders, to academics, and everyone on the street, we heard a consistent song: Oil had spiked in price and was GOING HIGHER. This consistent message convinced us all we should change our behavior. We started buying smaller cars and paying attention to things like gas mileage. The Honda Civic had the most bland commercial on TV: it promised (and delivered) over 40 MPG.

Contrast this to today. Every day for the last 5 years you have been told that high oil prices are the fault of one group or another (but never the consumer). When oil hit $30/Bbl, you were told to just wait, because it would come back down. At $50, you were again told it was just speculators, that it would get better. At $70: same thing, and again at $100, and now at $118 or so. You are being fed the line that the politicians can fix it by calling Big Oil in front of Congress, by suspending gas taxes, by taxing oil companies for "excess profits". Not only is this ridiculous, but it allows the consumer to avoid coming to the conclusion that our HABITS MUST CHANGE. Instead....if you just wait one more week, one more month, one more year, they tell you it will all be fixed for you.

It won't. Certainly not by the proposals being floated by certain politicians.

In a commodity market where demand grows in linear fashion, but supply comes in discreet stair-step chunks (and only with massive investment over a long time), you get periods where PRICE is the only way the market finds balance. Price is the arbiter of who gets what, when. Price determines highest and best use.

In this type of market, there are two solutions to reduce price, an ONLY two solutions. One is to increase supply, and the other is to decrease demand. High price is the only signal to participants that causes them to either use less or produce more. If the price signal is not strong enough for either side of the equation, it continues to rise until one side finally moves. Right now, the oil companies are drilling at a historic pace, so they have responded to the price signals. But oil isn't discovered and brought to market the next day. It can take years. So, it is now the consumer who has not yet taken the price signal (both here and abroad). And instead of encouraging the consumer to do so, politicos are suggesting that we actually MUTE the signal by lowering gas taxes in the short run. And then they compound this by suggesting we increase taxes on producers of oil, which would lead to less drilling and production.

These misguided policies only serve to make the problem worse by decreasing supply and keeping demand high. Given that they have it exactly backwards (and I really don't think they are that stupid), I can only come to the conclusion that they don't really mean any of this, but it sells in an election year. The problem is that some people actually believe them, and I would hate to see us repeat the mistakes of the past on an even grander scale today.

So I say please to Ms. Clinton and Mr. McCain:
#1) take at least one Economics Course
#2) Visit an AA meeting

NYT: On Carbon, Tax and Don’t Spend

2008-03-25T07:42:00.000-07:00

Carbon taxation makes much more sense than a cap and trade system, which just shifts the problem instead of removing it. One doesn't have to look farther than the EU ETS to see the miasma of problems cap and trade faces. The primary reason cap and trade gets political support is because it appeases the lobbyists, who realize that carbon legislation is imminent and therefore support the scheme that protects their balance sheets as much as possible. As Ms. Prasad suggests, tax the CO2 producers, earmark the money specifically for clean energy programs, and be done with it.

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The New York Times

March 25, 2008
Op-Ed Contributor
On Carbon, Tax and Don’t Spend
By MONICA PRASAD

Evanston, Ill.

EVERYONE seems to be talking about a carbon tax. It’s probably the most glamorous — and certainly the most unlikely — use of the tax code since Al Capone got hooked for tax evasion.

The idea is that polluters should pay for the environmental damage they cause. Slap a tax on carbon, the theory goes, and you will get fewer carbon emissions, more revenue for government and energy independence, all at the same time. No wonder people from both sides of the political divide have come out in support of it.

But a carbon tax isn’t a new idea. Denmark, Finland, Norway and Sweden have had carbon taxes in place since the 1990s, but the tax has not led to large declines in emissions in most of these countries — in the case of Norway, emissions have actually increased by 43 percent per capita. An economist might say this is fine; as long as the cost of the environmental damage is being internalized, the tax is working — and emissions might have been even higher without the tax. But what environmentalist would be happy with a 43 percent increase in emissions?

The one country in which carbon taxes have led to a large decrease in emissions is Denmark, whose per capita carbon dioxide emissions were nearly 15 percent lower in 2005 than in 1990. And Denmark accomplished this while posting a remarkably strong economic record and without relying on nuclear power.

What did Denmark do right? There are many elements to its success, but taken together, the insight they provide is that if reducing emissions is the goal, then a carbon tax is a tax you want to impose but never collect.

This is a hard lesson to learn. The very thought of new tax revenue has a way of changing the priorities of the most hard-headed politicians — even Genghis Khan learned to be peaceful, the story goes, when he saw how much more rewarding it was to tax peasants than to kill them. But if we want lower emissions, the goal of a carbon tax is to prompt producers to change their behavior, not to allow them to continue polluting while handing over cash to the government.

How do you get them to change? First, you prevent policy makers from turning the tax into a cash cow. Carbon tax discussions always seem to devolve into gleeful suggestions for ways to spend the revenue. Reduce the income tax? Give the money to low-income consumers? Use it to pay for health care? Everyone seems to forget that the amount of revenue is directly tied to the amount of pollution that is still going on.

Denmark avoids the temptation to maximize the tax revenue by giving the proceeds back to industry, earmarking much of it to subsidize environmental innovation. Danish firms are pushed away from carbon and pulled into environmental innovation, and the country’s economy isn’t put at a competitive disadvantage. So this is lesson No. 1 from Denmark.

The second lesson is that the carbon tax worked in Denmark because it was easy for Danish firms to switch to cleaner fuels. Danish policy makers made huge investments in renewable energy and subsidized environmental innovation. Denmark back then was more reliant on coal than the other three countries were (but not more so than the United States is today), so when the tax gave companies a reason to leave coal and the investments in renewable energy gave them an easy way to do so, they switched. The key was providing easy substitutes.

The next president of the United States seems sure to be more committed to environmental policy than the current president is, and a carbon tax is high on everyone’s list of options. Indeed, a carbon tax has been promoted almost as a panacea — just pop in the economic incentives and watch them work their magic. But unless steps are taken to lock the tax revenue away from policymakers and invest in substitutes, a carbon tax could lead to more revenue rather than to less pollution.

An increase in gasoline taxes — the first instinct of many American policy makers when the idea of a carbon tax comes up — would likewise be the wrong policy for the United States. Higher gas taxes would raise revenue but do little to curb pollution.

Instead, if we want to reduce carbon emissions, then we should follow Denmark’s example: tax the industrial emission of carbon and return the revenue to industry through subsidies for research and investment in alternative energy sources, cleaner-burning fuel, carbon-capture technologies and other environmental innovations.

Monica Prasad, an assistant professor of sociology and a faculty fellow at the Institute for Policy Research at Northwestern University, is the author of “The Politics of Free Markets.”

Copyright 2008 The New York Times Company

Printer ink tops $1000 a barrel

2008-01-28T08:36:00.000-08:00

Although this is meant to be a parody on $100 oil, there probably is some truth to it. We did a look a while back at the sale price of several common liquids on a per barrel basis, and crude oil still comes out the cheapest, and by a significant margin. For example, one 24 oz. bottled water at $1.00 equates to $167 a barrel (a buck for a bottled water is being generous, mind you) while crude oil still hasn't closed trading at $100 a barrel. When you factor in the cost of bringing that barrel of water to market versus bringing a barrel of crude oil, it's apparent that the profit margin differential is in bottled water's favor. From an environmental standpoint, bottled water is a culprit of environmental impact just as oil is; the common view, it seems, ignores the impact of making and disposing of all those empty polyethylene terephthalate bottles. We can more easily wean our bottled water addiction than our oil dependency, and provide relief to our wallets and our environment in the process. We'll need all the money we can get to buy more printer ink anyhow... (Thanks to TeamBiscuit for the article!)
---

The grim economic picture darkened further today with news that the price of ink for printer cartridges has reached an all time high of $1000 a barrel on the New York futures exchange. The world’s most traded commodity has seen a steady rise in price over recent months due to supply problems, increased demand from China and a failure of consumers to send their empty cartridges to the charity recycling centre and just leaving them in their desk drawer instead.

The computer industry urged the public not to panic and to only print out essential documents while they set about finding alternative ways for children to get colouring-in pictures that they print out from the Disney website. In some parts of the world, people are having to print out documents in blue or even green ink, continually having to pause to over-ride the irritating instruction from their bleeping printer to change the black ink cartridge.

A statement from Hewlett Packard conceded that much of the increased cost may have to be passed on to the consumer claiming, ‘It’s only right and fair that computer printing ink and peripherals suppliers sustain their profits in this area to fund further research…’ The rest of the statement was illegible as the print became too faint.

So dependent is the global economy on printer ink, that there are concerns that the United States may take military action against crude ink producers in the Middle East unless the situation improves. ‘You know what the invasion of Iraq was really about, don’t you?’ said Spike Harris of the Stop the War Coalition. ‘Printer ink, yeah! PresidINK Bush is in the pay of the big ink companies, and the whole lot of ‘em have got blood on their hands. And black ink obviously.’

Posted: 27 January 2008 by TeamBiscuit

Claiming the High Ground in the PHEV Space

2007-11-07T09:48:00.000-08:00

My views on the validity of plug-in hybrid electric vehicles will be tested in fairly short order, when Fisker Automotive launches its first car in 2009-2010. The company has the chance to take the early lead at the high-end of the PHEV space. While there may be competitors like the Chevy Volt hot on their heels at lower prices, there is room for a variety of cars across the price-quality spectrum. This is no different than the existing car market: some people who buy a Chevy wouldn't consider a BMW, and vice versa. So while cars are essentially commodities that at their essence perform the same task, individual desires and tastes allow large markets for both a $20,000 Hyundai and an $80,000 Mercedes. The stunning car presented in Fisker's press release last week indicates that these true "car guys" understand that cars will not be sold on efficiency alone, but also based on style, performance, and luxury. And if you can have it all and be "greener than Gore", why not?

The Best Alternative Fuel

2007-10-19T10:41:00.001-07:00

Whenever people ask me about the "best" alternative fuels, I always start by reminding them that the first distinction to be made is "alternative to WHAT"? Do you mean an alternative to crude oil and its derivatives in the transportation segment, or are you talking about alternatives to coal used for 50% of our power production? So, as a start to today's discussion, I will point out that I am discussing alternatives to crude oil, or more specifically to gasoline and petro-diesel. At the end of this post, I will tell you which alternative fuel I believe to be the "best".

The next thing we remind ourselves of are the reasons WHY we are seeking alternatives to crude oil. Depending on who you are talking to and what their goals are, the answer as to "best" alternatives may change. Unfortunately, none of these goals are mutually exclusive and I like to think about our four key goals as interconnected in this manner:

"Growth": to provide needed energy for growing economies around the world
"Price": to keep the growth in energy demand from increasing prices to the point where they hurt the economy
"Emissions": to reduce NOx, SOx, Mercury, Particulates, and CO2
"Dependence": to reduce our crude oil imports for reasons of security and geopolitics

Focusing on all goals in the aggregate helps in determining an optimal alternative strategy. So when we consider certain alternatives to crude oil and gasoline in light of each of these goals, here's how they stack up:

Ethanol is good on the dependence goal but fails to deliver the ability to grow beyond a certain level (unless we can overcome the significant barriers to cellulosic ethanol). Ethanol also may ultimately be difficult on the price issue, as cost of inputs (e.g.: corn) increases dramatically with scale. From an emissions standpoint, ethanol may be Co2 neutral, but it gets less mileage than gasoline and may increase other emissions on a per-mile-driven basis.

Biodiesel: Same issues as ethanol when you try to scale this larger, as there are not enough feedstocks (including used veggie oil, soy oil, palm oil, etc) to provide any meaningful amount of fuel relative to our usage. Algae may provide some help on feedstocks, but that is many years away. Biodiesel's advantage over ethanol is that is works better in existing infrastructure and it gets significantly better mileage than ethanol (diesel engines get better mileage as they run at higher compression rates, thereby better utilizing the fuel). Biodiesel also may get slightly better mileage than what it replaces (petroleum based diesel), unlike ethanol vs. gasoline. So compared to ethanol, it's a better fuel, and it's used in a better engine.

Fischer-Tropsch Diesel: Using syngas and a Fischer-Tropsch reactor to make diesel from coal, natural gas, or biomass is superior to ethanol and biodiesel because it scales very nicely - there is lots of coal for feedstock purposes. It is cheaper than oil at current prices, and it is wholly U.S. based, so it helps the dependency goal. From an emission standpoint, it is partly better than ethanol because, again, it is used in a diesel engine and therefore can get twice the mileage. So while each gallon may have greater emissions than ethanol, that impact is reduced by the way each gallon is efficiently used. F-T diesel is significantly lower than it's petro-diesel counterpart on most emissions, but both ethanol and F-T diesel emit CO2 at the tailpipe. Of course, ethanol has a lower CO2 footprint due to biomass feedstock, but both F-T diesel and ethanol emit lots of CO2 at the plant production level. Importantly, in both cases, the CO2 comes off the plants in a pure form that can be gathered and sent into a pipeline for sequestration or use in industrial applications or in enhanced oil recovery.

This is not an exhaustive list, but you get the idea. So which is the best alternative?...

EFFICIENCY!: By using less in the first place, we reduce dependency, put less upward pressure on price, allow room for growth, and reduce emissions. My view is that our energy policy should not be pushing new fuels, but looking for ways to use less of what fuels we have. The simplest way to do that right now is by deploying smaller, more efficient engines, using more high-efficiency diesel engines, and by electrifying the car to a greater degree. The best way to use electricity in a car is with a Plug-In Hybrid Electric car. This allows most efficient use of a battery along with the convenient and ubiquitous nature of a gasoline or diesel engine. Using battery power with electricity sourced from the grid allows us to move the energy generation to larger-scale, highly efficient power plants, using nuclear (20% of U.S. electricity), high efficiency combined-cycle natural gas plants (another 20% of our electric mix), solar, wind, and coal.

Some people argue that using coal-based electricity to power cars merely moves the tailpipe emissions to another location. This isn't the case, since the generation efficiency of large-scale plants is significantly better than in a car engine. Secondly, an electric engine in a car is more efficient at turning power into motion. This EPRI study: "Environmental Assessment of Plug-In Hybrid Electric Vehicles" shows that using a PHEV, even backed by the least efficient old coal plants for electric generation, results in better well-to-wheels efficiency and greenhouse gas emissions than our traditional auto fleet. And if we use lower Co2 electricity generation over time (nuclear, Combined Cycle gas plants, etc), it gets even better.

Efficiency via the use of diesel engines and PHEV's therefore satisfy all the goals we sought out to reach. This, in my humble opinion, represents our "best" alternative fuel.

If you want to know more about PHEVs, a very smart Analyst named Saurin Shah wrote some comprehensive research on the topic for Alliance Bernstein in 2006. The report is available online and is titled: "The Emergence of Hybrid Vehicles"

And since I am plugging publications, I will also note an interesting book by Judy and Curtis Anderson entitled "Electric and Hybrid Cars, A History".

Sulfur fines

2007-10-15T06:04:00.000-07:00

As a follow-up to my post in May called "Sulfur, sulfur everywhere", news today out of Kazakhstan ("Chevron Kazakh unit fined $307 Million") shows how this sulfur glut is starting to impact companies like Chevron. Whether the Kazakh fine is valid or not, I believe we will start hearing about this in the Canadian oil sands as well.

Bob Lutz on diesel vehicles in America

2007-07-13T07:37:00.000-07:00

This video is of Robert Lutz, GM's Vice-Chairman of Global Product Development, on GM's FastLane Blog. To no one's surprise, he talks of the economic impracticality of ULSD vehicles in the US and is skeptical that consumers would be willing to spend an extra $4,000 or so to get one over a traditional gasoline Internal Combustion Engine (ICE) model. Bob also says that GM's "German Competitors" believe in the technology and the adoption of it in the states, and he thinks they are probably wrong, yet GM will roll out ULSD models just in case.

Ford has taken a similar stance, more of a 'wait and see' attitude. Though it's a bit cliche to justify American automakers' woes on their unwillingness to change with the rising tide, if the shoe fits... Most indications seem to point towards a shift towards ULSD vehicles, or at the very least away from gasoline vehicles. From an environmental standpoint, ULSD versus regular gasoline is an improvement on emissions. Lutz laments on the stringent standards imposed federally and the even more tight standards in California, the Northeast, and now Florida. These standards force GM to comply by making more expensive vehicles, which he doesn't think consumers will buy. If the consumer didn't have a choice this would be a non-issue, but the only group that can force the hand of the capitalist firm is the government, and in this country the government makes it policies based on the demands of the people, that is unless an outside influence dissuades them. But what lobbyist groups would be against diesel vehicles in the US? Here is a link to a lobbying spending database if you want to do some digging into the issue. You won't need a big shovel, that's for sure.

Summer's a Coming

2007-06-18T00:01:00.000-07:00

In a bullish sign for world crude prices, SK Corp., South Korea's largest oil refiner, last week purchased 700,000 barrels of oil for August delivery from ONGC, India's state-owned oil concern. The contract stipulates a $7.25-$7.50 premium above the average of Dubai and Oman crude, which implies a sale price of roughly $72.25, depending on the date of contract pricing. The announcement was made June 11th, which represented a $5 premium to Brent and a $7 premium to NYMEX as of the date of the announcement, for contracts of the same month. Not surprisingly, oil rallied the rest of the week. The "OTEN" "GO" function on Bloomberg provides a listing of similar transactions. Monday announcements may be worth reviewing.

If actions speak louder than words, then SK Corp is saying a lot. The company clearly believes it prudent to lock up supply, and the 10% premium to Middle East spot prices gives a good idea of where they think oil is headed this summer. The announcement also underscores the ability of refiners to deal directly with E&P. Do presumed levels of speculative buying in the futures market reflect these types of transactions?

Bloomberg Tickers: SK Corp: 003600 KS Equity; ONGC: ONGC IN Equity

Natural Gas and Oilfield Service Intensity

2007-05-31T06:37:00.000-07:00

Back in November, when natural gas prices had fallen hard and many were wondering where the floor price was, I published an entry here called "Natural gas prices: Why $7 is the new $3". I mentioned that drilling rig costs are not as important to overall finding costs as they once were, due to the nature of the unconventional gas reservoirs we now target and the cost of well completions relative to drilling costs. It is a good time to discuss that statement, since I believe the average citizen does not recognize the incredible increase in asset utilization and the technological improvements that have been required just to keep our U.S. natural gas production flat over the last few years. But first, a quick reminder of natural gas supply fundamentals, for those who don't worry about this stuff every day.

The U.S. is the second largest producer of natural gas in the world, just behind Russia. We produce about 50 billion cubic feet (bcf) per day.We also import another 10-12 bcf per day, primarily via pipeline from Canada, but also a small amount in the form of liquefied natural gas (LNG), with our largest LNG provider being Trinidad.

As for our sources of natural gas, that profile has been changing over the years.
Production from the Gulf of Mexico, where large, high-rate wells were the norm 20 years ago, is giving way to more onshore production , specifically from tighter sands, coalbed methane, deep gas, and gas shales, collectively known as "unconventional" gas reservoirs (labeled so because gas from these formations were difficult to produce with available technology just a few years ago). The Energy Information Administration shows this trend in historical data and in their projections through 2030, shown here.

We will discuss demand increases in another post, and more importantly, the components of demand that have dramatically changed to make prices demand less price-sensitive than in the past. For now, let's focus on how much we have to drill in order to keep production at least stable. The chart below shows, for each month over the last 10 years, the average daily production of natural gas in the U.S.:
Note that production peaked in 2001. This is in spite of the fact that prices have risen from around $2.00 per MCF to around $8 per MCF today. Natural gas producers have every financial incentive to bring more supply to market. However, there are a number of factors that make this difficult, some of which I discussed back in November in "$7 is the New $3":
1) targets are smaller than ever before
2) costs are increasing as demand for services is high and service providers are stretched to their limits
3) production decline rates on new wells are steeper than previously, partly due to the application of new methodologies such as directional and horizontal drilling, fractionation, chemical stimulation, and other well completion technologies.

So here is the key chart to see here...
it compares the declining gas production number to the number of wells we are drilling. Note that in 2006 we drilled a record number of gas wells, almost 30,000 of them, almost triple what we drilled just in 1999, and yet we got no appreciable production increase. That said, we are beginning to see an increase in production in 2007 that may be a delayed response to the last 12 months torrid drilling pace. The delay may be partly due to the fact that many wells get drilled but have to wait for a completion crew or for pipeline connections.

So, of course, with more wells to drill, more rigs are being put to work, to the point where we are building new rigs in the U.S. after many years of having been over-supplied.

Virtually every available rig is now working, but many people believe the new-builds coming into the market will hurt the drillers. My contention, and a view held by many rig operators, is that the new ones will merely replace the older rigs that are not fit for today's intense drilling requirements.

Wells are being drilled deeper than before, through more complex geology, and with longer horizontal laterals. This requires higher-spec drilling rigs, more complex tools, more pipe, and more experienced personnel. All these things are harder to get in this very robust drilling environment. Note that while the number of gas rigs employed has risen dramatically, horizontal and directional rigs have been the fastest growth area.

Uncoventional gas, by definition, is costlier to produce and requires a greater amount of applied technology. 20 years ago, the primary equipment required to drill a vertical well into conventional gas was the drilling rig. The cost of that rig on a "day rate" basis was the most important factor in the cost of a well.However, today's unconventional gas wells have cost structures with more non-rig costs and completion costs. That is, the rig may be less important than the downhole tools like Measurement-While-Drilling ("MWD"), Logging-While-Drilling ("LWD") , and 3-D Rotary Steerable tools. Once you have drilled the hole, you may need pressure pumping equipment to fractionate the well, chemicals to pump into the formation for optimal well performance, and other specialized well completion services. The total cost of many of today's gas wells may be half completion costs, which have nothing to do with rig costs. This is why I have said that rig rates themselves may not be the same leading indicator they once were. Rising rig costs may no longer be the ultimate determining factor of whether or not a well is economic. Oil and gas production companies may be somewhat less price sensitive when it comes to rig costs, per se. They will care much more about rig efficiency and rig capability.

The bottom line is that increasing rig rates do not spell disaster for the market, nor is the arrival of new-build rigs with higher capabilities. With the rise of horizontal and directional drilling, declining production from mature basins like the Gulf of Mexico, and the increase in well complexity, natural gas looks to keep the U.S. oilfield service market very busy for some time to come.

Sulfur, sulfur everywhere

2007-05-25T15:29:00.001-07:00

A number of recent experiences have me thinking again about sulfur. More specifically, about how much sulfur we produce and whether we are headed toward an overabundance that could hamper oil production and gasoline refining. Typically, sulfur production is a good thing (as opposed to sulfur emissions, which are not a good thing). Sulfur is one of the most widely used industrial chemicals on earth. It is a key component in certain fertilizers and is used in many other applications. Increasing sulfur consumption is often thought of as an indicator of strong growth of an industrial economy. But the convergence of a few trends has me wondering if sulfur production may get too high to dispose of it all (or at a minimum, decrease its value so much that it becomes a liability).

The first trend is the increase of high-sulfur crude oils being produced in the world. The second trend is the significantly lower sulfur content standards for end-product fuels, specifically Ultra-Low-Sulfur-Diesel (ULSD). The third trend is the increasing production of Canadian Oil Sands bitumen and the sulfur produced from that activity, and the final trend is the increase in natural gas production from sour (high-sulfur) gas wells.

My first thought on the subject came on a trip to the Athabasca oil sands of Northern Alberta. Along the Athabasca River outside the city of Fort McMurray I took this photo of a gigantic pile of sulfur. Looks to be about the size of CAL's football stadium:

I asked where it would ultimately go but did not get any satisfactory answer…sort of a “we’re stockpiling it for now”. When I asked an executive at another major oil company where there sulfur goes, he merely replied that there is always a market for it, but he didn’t pay much attention to who the buyers were. The answer in Canada is that they export a lot of it to the U.S. The U.S. G.S. reports that of the roughly 4 million tons of sulfur and sulfuric acid imported into the U.S. each year, Canada supplies over 70% of it. The U.S. produces about 8 million tons per year and therefore uses a total of about 12 million tons per year with agricultural chemicals being the major user. The price of sulfur per ton has actually risen from about $12 in 2002 to $32 in 2004 and has trended back down to around $28 as of 2006.

Refiners have been upgrading to handle more high-sulfur crude oil inputs, which sell at an increasingly large discount to sweeter West Texas Intermediate. ULSD in the U.S. has now moved to a standard below 15 parts-per-million (PPM) from 500 PPM just a few years ago. With more coming in the front end and less going out the back, sulfur extraction will reach all-time highs at refineries and natural gas processing plants over the next few years. Maybe we won’t have any problem selling it into an expanding worldwide economy, but at the very least, price pressures should exist for a long time. My next stop is figuring out whether we will reach a point where the inability to dispose of sulfur could be a hindrance to refinery operations.

high gas prices? who's to blame?

2007-05-25T09:48:00.000-07:00

Since Memorial Day is upon us and Americans tend to drive more than usual on this 3-day weekend, there is increased clamor about the high gas prices at the pump. Many politicians have seized this opportunity to go after big oil companies with accusations of price gouging. It is easy to take this position and point fingers at ExxonMobil and their ilk for taking advantage of us; unfortunately, the truth is a bit more complicated and inevitably leads right back to us, we who drive large inefficient vehicles and show no signs of changing. Simple economics applies. If you want lower gasoline prices, then get more efficient vehicles; drive less; use public transportation; walk more; in other words, lower the demand for gas and the price should follow. Until wholesale changes in our transportation habits happen, expect gasoline prices to keep rising. $4 a gallon might look pretty cheap in hindsight. Remember when $2.50/gal was expensive?

On the bright side of all this, higher gasoline prices will likely predicate greater incentive to fund alternative fuels which, as of yet, are still too expensive to fully adopt.

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Wall Street Journal
May 25, 2007

Pains at the Pump
Page A14

It's Memorial Day weekend and the start of the summer driving season, so naturally it's time for Congress to grandstand against $3-a-gallon gasoline. And right on cue, the House passed legislation this week to criminalize gasoline "price gouging," whatever that is. Perhaps this is all designed to distract the public from Congress's own role in raising gas prices.

Under the anti-gouging law, service station owners could face up to 10 years in prison if they dare to raise their prices too much when supplies are low. Representative Bart Stupak, the Michigan Democrat who sponsored this scheme, said the vote would determine whether Members "side with Big Oil" or "side with consumers who are being ripped off at the gas pump." Who elects these guys?

The inconvenient fact is that there's no evidence of price rigging by Big Oil or the tens of thousands of independent service station owners across America. The causes of higher gas prices include $65 per barrel oil caused by rising global demand and geopolitical tensions; a record high U.S. gasoline consumption of 380 million gallons a day; and refined gasoline shortages caused by Congressional rules and mandates. Far from withholding production to raise prices, U.S. gasoline production of 8.8 million barrels per day is higher than any time in history and refineries are getting more gas per barrel of oil than ever before.

This isn't the first time a spike in gas prices has prompted Congress to allege price fixing. It's not even the second, third or 10th time. Since the OPEC oil embargo some 34 years ago, Congress has requested more than 30 investigations into whether energy companies have conspired to inflate profits. In nearly every instance, the Federal Trade Commission or the Department of Energy have found no evidence of price fixing. Only last year, Congress ordered the FTC to investigate whether Big Oil had manipulated prices after Hurricane Katrina in 2005. The agency found "no instances of illegal market manipulation that led to higher prices."

What does "gouging" mean anyway? No one on Capitol Hill can answer that question. The House bill prohibits energy companies from charging a price that is "unconscionably excessive." There's a precise legal term. It further explains that it shall be a crime whenever "the seller is taking unfair advantage of unusual market conditions" or "the circumstances of an emergency to increase prices unreasonably."

Still confused? Perhaps this will help. Gouging occurs, says the bill, whenever "the amount charged represents a gross disparity between the price" sold at the pump "and the average price at which it was offered for sale by the seller during the preceding 30 days." That could cover any price spike for any reason. Or gouging may occur when "the amount charged grossly exceeds the price at which the same or similar crude oil, gasoline, or natural gas was readily obtainable by other purchasers in the same geographic area." So if your oil supplier charges more than a competitor's does and you then raise prices, you could be a felon.

In other words, we are all criminals now. No one seriously believes this law will lower prices for consumers, but you can bet that brigades of lawyers will earn fat fees sorting out what exactly is meant by "unreasonably," "gross disparity" and "excessive."

If Congress wants to locate genuine gas price villains, it should look in the mirror. Domestic refining capacity is stretched in part because environmental laws discourage the building of new refineries. Meanwhile, new mandates for ethanol and other "boutique" gasoline blends make it harder for the industry to meet refining shortfalls. The Lundberg Survey estimates that the ethanol mandate alone adds 10 cents to each gallon, and that 36 refinery snafus this year have cut U.S. gas supplies by about 8%. Refiners are also currently switching to mandated summer gasoline blends -- another contributor to the current price spike.

Congress's ethanol craze is a special problem because it further reduces the incentive to invest in new refining capacity. Gasoline refining is a low margin business in any event, and only a very brave, or very foolish, CEO would invest heavily to refine more gasoline when Congress is bent on replacing it with ethanol in the future.

If Congress wants really high prices, it should keep this up. After Hurricane Katrina, several states including Virginia strictly enforced price gouging laws, and many service stations simply ran out of gas altogether. Gas wasn't available at any price. Last year's FTC report pointedly advised Congress that "federal gasoline price gouging laws that have the effect of controlling prices likely will do consumers more harm than good." It added that, "Competitive market forces should be allowed to determine the price of gasoline drivers pay at the pump." Such a lesson in supply and demand seems beyond Congressional understanding.

URL for this article:
http://online.wsj.com/article/SB118005955366914296.html

Coal-to-liquids diesel vs. Ethanol

2007-05-22T16:00:00.000-07:00

An AP article earlier this month by H. Josef Hebert entitled "Ethanol Bill Heads to Full Senate, Prompts Debate over Coal as Motor Fuel" points out the bipartisan support for a bill that would try to replace a quarter of all our gasoline consumption with ethanol. Then it goes on to say that a measure to encourage production of clean diesel from coal-to-liquids processes was defeated along party lines. The reasons cited were concerns over global warming and specifically that coal-based fuels generate more CO2 than conventional gasoline. Unfortunately, that may be somewhat of an invalid argument.

I feel compelled once again to remind my friends that burning ethanol in your car produces CO2 at the tailpipe, as we have pointed out here in the past (see prior post titled: "Burning ethanol in your car releases CO2" . In fact, when you take into account that a typical E-85 flex-fuel vehicle gets a likely 15 MPG and a typical diesel powered car might get 30 MPG, then the ethanol burning car emits MORE CO2 on a per-mile-driven basis than the coal-based diesel car at the tailpipe.

The tailpipe distinction is key, because processing coal into liquid fuel emits CO2 at the plant level, and the process of making ethanol at a plant also emits CO2 (yet much less than the coal process). The difference is that a coal-to-liquids plant puts off CO2 in relatively pure, elemental form. This means the CO2 can readily be sequestered and put into a pipeline to move around the country for uses such as injection into EOR projects, etc.

I don't mind so much the coal-to-liquids process being dismissed if the reasons were based in fact, but I have a hard time when the same politicians accept the concept that we can just mandate our way to making 30 billion gallons of ethanol a year in just a few short years. We've said it before and will gain: there isn't enough land to do it with corn, there isn't the climate to do it with sugar, and there isn't enough time to do it with cellulosic material (we are trying to undo millions of years of plant evolution that has made cellulosic material very difficult to break down).

If we want to reduce CO2, the solution is clear: burn less fuel. Don't try to come up with a new fuel. So to burn less fuel, you have to use more efficient engines. That is where various technologies come into play. Not just hybrids, but also diesels and possibly compressed natural gas engines. Finally, if you really want to burn less fuel, just allow it to be more expensive. But that is the subject for another day...

More Inconvenient, more Truth?

2007-03-20T14:28:00.000-07:00

Are you a reasonable person with a desire to understand difficult topics? Are you willing to suspend disbelief for an hour or so? Did you see "An Inconvenient Truth"? If you gave a couple hours and a few bucks to see that, I would also think you might enjoy seeing this documentary aired on the BBC titled: "The Great Global Warming Swindle". Yes, the title is inflammatory, but if you get about 15 minutes into this, they have some very compelling data I have seen before but herein is put together very nicely to make a good scientific case. The most important point, I believe, is that while CO2 and climate are clearly linked, the data may indicate that CO2 is the effect, not the cause, in the relationship. Again, if you are a reasonable person who is willing at least to entertain more than one point of view, I think it is worth viewing. If you have already made up your mind, either way, then don't bother...go spend your hour in some other productive manner. Again, I'm not suggesting which side of the debate you should believe, I will leave that up to you, and over time we will all get more data.

Why a hydrogen economy doesn't make sense

2006-12-12T09:30:00.000-08:00

from PhysOrg.com

In a recent study, fuel cell expert Ulf Bossel explains that a hydrogen economy is a wasteful economy. The large amount of energy required to isolate hydrogen from natural compounds (water, natural gas, biomass), package the light gas by compression or liquefaction, transfer the energy carrier to the user, plus the energy lost when it is converted to useful electricity with fuel cells, leaves around 25% for practical use — an unacceptable value to run an economy in a sustainable future. Only niche applications like submarines and spacecraft might use hydrogen.

[...]

on China

2006-12-12T08:53:00.000-08:00

The rampant buzz on China's bright economic future has caused me--and I'm guessing at least a few others--to overlook some prime issues that Americans take for granted, such as how will the modern Chinese meet their basic needs, like food and water? I came across these two articles from Seed Magazine in succession and didn't make the connection until a little later.

Issue 1 - The Chinese can't afford to give up food crops for biofuel:
Biofuels Seen as a Luxury

Issue 2 - Water is a problem too:
Beijing's Tap Running Dry

Mainland China out-numbers the US by ~4.5X and has a younger population. Picture our domestic energy issues and quadruple them, and then take biofuels out of the solution. Environmentally, this could be bad. Politically, this could be really bad. The United States grew into modernization over the course of a few hundred years while China is trying to do it in a fraction of the time; I just hope that they are planning accordingly since there is plenty of room for error, assuming that they have more people and a smaller time frame.

Going it alone?

2006-11-24T15:55:00.000-08:00

from Stanford Magazine.

When it comes to energy policy, America's independent streak may hurt us more than help us.

no such thing as a free lunch

2006-11-15T10:15:00.000-08:00

Global warming/climate change/greenhouse gases is a global epidemic. There is a lot of sentiment out there to reduce carbon emissions, with the fingers pointing towards the US. What bothers me is that countries such as China and India, which could likely surpass the United States in carbon emissions within the very near future, have been publicly lamenting that they cannot control emissions like the US should because it would hinder their economic growth.

Doesn't it hinder America's economic growth too?

I am fully supportive of the economic renaissance of India, China, and other countries; I do believe, however, that there are costs in any project that cannot be swept under the rug and if an entity can't compete with all costs considered, then perhaps they shouldn't. Is it fair to expect American companies to spend the incremental dollar towards carbon control and give other economically-disadvantaged countries full license to let their smoke stacks go unfiltered? Beyond the fairness factor is the cold (or should I say, inconvenient) truth that if pumping bad stuff in the sky is wrong and we have the means to control it, then there should be no selectiveness--everyone must participate. There has to be a better solution available.

I found Sethi's justifications to be a bit hackneyed, "I do not have the funds for both [energy efficiency vs. poverty reduction]. My choice is to improve the lot of India's poor or reduce CO2 emissions so the developed world can breathe easier." Well, if you spin it like that it is hard to argue against helping the poor. Throwing a red herring at my moral compass can work for only so long, though.

Fix the Kyoto Protocol to include China and India, prompting the US to ratify the thing, and let's move forward.

Carbon Reduction or Poverty Reduction, Not Both

No need to worry?

2006-11-14T09:31:00.000-08:00

Cambridge Energy Research Associates (CERA) just released a new report on one of their favorite topics--debunking peak oil theory. CERA director of Oil Industry Activity Peter Jackson suggests in Why the Peak Oil Theory Falls Down: Myths, Legends, and the Future of Oil Resources we have over 3X the reserves that peak oil theorists suggest, 3.74 trillion barrels compared to 1.2 trillion barrels.

We haven't read the report yet, just the news release and Daniel Yergin's commentary on CNBC.
news release link

On a side note, I highly recommend Yergin's book The Prize to learn about the history of oil.
The Prize link on Amazon

Energy Links 11/14/06

2006-11-14T07:51:00.000-08:00

We're going to try to post interesting links on a relatively consistent basis here on the Dave's Energy blog. As of now it will be a link dump with commentary here and there, but if healthy discussion from our readers persist we'll try to spread the links out and give our two-cents when applicable. Thanks for staying tuned and spread the word!

from WSJ.com:
Russia provides ~25% of Europe's natural gas and have been in political fisticuffs with many countries and entities over their influence. This is a theme that will likely escalate before it will go away.
Bypassing a Major Oil Choke Point
Georgia, Russia Feel Tensions Rise With Price of Natural Gas

Weather is beginning to make it's impact on the oil and natural gas markets
Oil Prices Fall Amid Mild Weather, High Inventories

Enron is still a dirty word in most circles, yet their trading strategies are lauded and coveted by Wall Street
Trading on the Enron Mystique

from csmonitor.com:
Move off the grid! Equip your home with solar panels, a micro wind turbine, and a micro CHP (Combined Heat and Power) unit and you could potentially produce enough energy to be self-sustaining. The $64,000 question remains, though--is it worth spending tens of thousands of dollars up front, or will you actually be better off sticking with the utility company?
It heats. It powers. Is it the future of home energy?

The Rand Corporation just released a report on renewable energy. Lots of good information inside.
Impacts on U.S. Energy Expenditures of Increasing Renewable Energy Use (in PDF)

Natural gas prices: Why $7 is the new $3

2006-11-06T06:28:00.000-08:00

Natural gas prices have been volatile, and there are no end to the different opinions you can get as to the future of gas prices. I get asked about gas prices quite a bit and over the last couple of years I have often stated that I believe $7 per mcf is the price at which we can see meaningful exploration and development of gas - enough to at least offset the significant decline rate of the average natural gas well in the U.S. This $7 view isn't anything earth-shattering, and is a view shared by many in the industry, but that isn't why we believe it to be true. It is based simply on the economics of drilling for natural gas in the somewhat mature basins of North America.

Let me start with the simple example I've shared over the years, an example from the "old days" of oil and gas (pre-2000). I'm simplifying here, but back then, if you were a producer that could find an MCF for $1, produce it for $1 and sell it for $3, you'd be pretty happy. This mathematical model allowed for growth in reserves and production and a positive return on capital. First you should recall that an oil and gas company needs to at least replace each unit of gas it produces with a like unit, otherwise it is just depleting away it's existing asset base. Therefore, the sale of each unit must generate enough excess cash flow to go replace that unit at a cost equal or below that excess cash flow. In the "old days" example this works out like this:

1) Drilling and completion cost of your latest well: $1,000,000
2) Size of new reserve from this well: 1,000,000 MCF (a.k.a. 1 billion cubic feet)
3) Fiding cost per MCF: $1,000,000 / 1,000,000 = $1.00 per MCF
4) Producing life (reserve life) of well: 10 years (note that production is not linear, that it comes on at the highest rate it will acheive and will decline over time due to reservoir and pressure depletion)
5) Lease Operating Cost per unit (to flow it from well, maintain well ops, etc): $1.00 per MCF
6) Sale price per MCF: $3.00

Therefore, each unit produced will generate cash flow of $3.00 minus $1.00 in lease operating costs, or $2.00 per unit. But now you have depleted your asset base by 1 unit, so what do you do? You take your $2.00 in cash flow and go invest it into a new drilling program. Since your finding costs are $1.00 per MCF for a 1 BCF well, you have the ability to replace your one unit produced with two more. This is essentially how you grow the company. In this case, your company would have the ability to replace reserves on a 2-to-1 basis. But note that producing one actual MCF unit doesn't actually get you two because you don't drill wells that are just two MCF in size. In the absence of borrowing money to drill, you actually need to produce enough of your existing reserve to get the money to drill the next well. In this case, you'd have to produce 500,000 mcf before you had enough money to drill your next $1MM well...this would take a few years.

So let's assume you have 10 BCF of total reserves at the begining of the example. You spent $10MM to develop those reserves and have total finding costs of $1.00 per MCF. Your average reserve life is about 10 years, so you are producing 1 BCf each year. You are therefore generating $2 in cash flow per MCF times 1 BCF for $2,000,000 per year. You can use that to drill 2 new wells at $1MM each and come up with another 2 BCF of new reserves. This would be considered a 200% reserve replacement ratio (2BCF new / 1 BCF produced). But although you replaced 200% of what you produced, your underlying reserve base grew by just 10%:

10 BCF - 1 BCF produced + 2 BCF found = 11 BCF.

In this case, you can grow your company's reserve base by 10% annually if you can acheive a 200% replacement ratio on production. Of course, if you have a bad year and you spend $2MM in drilling costs and only find 1 BCF of gas, you find that your reserves did not grow at all. This is essentially the position many of the larger integrated companies find themselves in: it is very hard to grow reserves once you get to a certain size.

So, how does all this relate to $7.00 gas? The fact is that finding costs on average have been climbing precipitously the last few years. We analyze operating data on over 75 publicly-traded exploration and production companies (micro-to-large cap, exlcuding the majors) and note that the average for 2005 was $2.77 per MCFe (the "e" stands for equivalent, meaning that oil volumes are included and converted to gas on a 6-to-1 basis). One year isn't all that meaningful, but we also look over 3 and 5 year drilling cycles to see how costs fare. We find that the 3-year average for our group is $2.50 per MCFe. We also note that the average per MCF operating costs are $1.60 for the group in 2005.

Therefore, in order to replicate the same economics as the "old days" example ($1-$1-$3), we need to generate a cash flow per MCF of double our finding costs, or $2.75 X 2 = $5.50. Given the $1.60 operating costs, that means that gas needs to sell for $7.10. So that is the short answer as to why I believe in $7.00 gas prices. While it is true that companies can replace reserves over 100% at levels below that, it is also true that they would not be able to generate any meaningful growth in reserves. Standing still at the same reserve level and merely replacing each unit you produce is not a way to create value.

All that said, there will be seasonal swings in prices. We will see prices well above $7 and well below $7. But the long-term average has to be $7 or so or "average" companies simply won't drill (that said, there are vast differences amongst companies' finding costs and operating costs - some will grow reserves at $4 gas and some can't do it even at $8 gas).

Also, I do not see any chance for average finding costs to come down significantly , but that is a topic for another day, when we can discuss why rig costs are not as important to overall finding costs as they once were (hint, it has to do with the type of reservoirs we are targeting and the nature of completions costs). And another day, we'll talk about why natural gas has become a more weather dependent commodity as prices have risen. Stay tuned...

Domestic, Clean, and Cost Competitive

2006-10-24T06:49:00.000-07:00

Last week, at the invitation of the fine people at Think Equity Partners, I had the opportunity to join in a round-table discussion with the senior folks from the U.S. DOE's Office of Energy Efficiency and Renewable Energy and the NREL (National Renewables Energy Lab). I used the opportunity to pose my ongoing question regarding our sometimes conflicting national priorities. That is, as a nation we speak about trying to accomplish several key goals over time, each of which might drive us toward potentially different solutions. My question was basically this: how does the administration view our ability to reconcile the competing goals of: 1) emissions reduction; 2) price containment (i.e.: reducing economic impact); 3) growth and; 4) security of supply.

The answer, of course, was that all were important. Specifically, Assistant Energy Secretary Karsner was clear that he seeks solutions that are "Domestic, Clean, and Cost Competitive". We further discussed how those same goals could be pursued differently whether you were talking about the Power market (trying to displace coal) or the transportation market (trying to displace crude oil). It became clear that the power market was much less of a focus at the moment, and that the DOE will be putting a great deal of effort behind biofuels, primarily because that is where they believe we can have the most impact. Their goals are to displace a significant percentage of our transportation fuels (30% or more) in a fairly short period of time. They clearly have a mandate to chase cellulosic solutions, solar opportunities, and other biofuels and were out meeting people like our group in order to find out where private capital can help move the programs forward. It was all somewhat encouraging. Given all the entrepreneurs I've been meeting lately with cellulosic ethanol plans and algae-based biodiesel plans, it will help for me to get out to the NREL and see some of their best science up close. More on all that later...

BTW, I think the DOE definitely heard from the private sector that capital will more likely be invested in those areas that have stable and predictable policy regimes. That may be too much to hope for in U.S. political arena, but we can always hope, can't we?

U.S. Natural Gas Storage Full? Here's a Secret...

2006-10-10T07:51:00.000-07:00

The dirty little secret is: It ALWAYS gets full. This year's dramatic drop in natural gas prices from their December highs started way back in January when we had the warmest period on record and used up very little of last year's storage (more on that in a minute). And yet during September the market seems to have been surprised by the fact that we are sitting at end of the gas injection season with nearly full storage again. Everyone knew this back in April. We all knew spot prices would fall as storage came closer to full as the marginal unit of gas output had fewer options as to where it could be stored or sold. Like others, we thought there could potentially be another big hurricance season to take more gas offline, but we weren't counting on it. What bothers me is that people, often very smart people, act now as if this near-term storage impaction has anything to do with the long-term economics of the natural gas exploration and production business. Stock prices for these companies have fallen hard as the market has taken near-term data and extrapolated it too far into the future. So now lets review why gas prices may be low now but why that has little to do with what prices will likely be next summer or next year, or over the next five years...

You hear alot of people saying the natural gas bull run is over because storage is getting full. To repeat myself: it always does. See the chart below:

The yellow band represents the range of high-to-low storage for any given week during the prior five years (on a rolling basis). The red line represents actual weekly reported storage. Note that the yellow band gets narrower at the top as the years go by...this is an indication that the amount of storage at year-end (just before the winter withdrawal season begins) tends to fall in a narrow range. You can also see this by looking at the tops of each year. There you see that we tend to have about 3200-3300 billion cubic feet (bcf) of gas in storage at end of season, even though the beginning of each year can be dramatically different - from an extreme low of 623 bcf in April 2003 to 1714 bcf in April 2006. So my point is still this: we always get full. The question is: At What Price?

Pricing and motivations
Natural gas buyers (utilities, industrial users, etc.) buy gas in summer and store it for winter when deliverability from existing production isn't high enough to meet high demand for winter heating, etc. If the price of gas in summer, plus the cost to store it, is less than the expected price in winter, then buyers have an incentive to buy and store. So buyers with an option to store gas look at the summer-winter spread and will buy gas in summer opportunistically as prices weaken. Some buyers will programatically buy regardless of price since they have contractual obligations to have a certain amount in storage. In each of the prior years, the spread between summer spot sprices and the futures prices (expectations) for gas in winter were fairly stable:

Source: Bloomberg data for Henry Hub Spot and generic NG6 future

In 2003, it took just a $0.53 spread between the average summer spot price and the winter futures to manage to add 2531 bcf into storage. We got full, at an average price of $5.28 that summer. That was a historic year as gas prices had never stayed that high in summer before - that high price was needed because we were starting out with such a low amount.

In 2004, it took a $1.00 spread to incentivize a build of 2307 bcf to get to full storage.

In 2005, it took a $1.18 spread to incentivize a build of 2025 bcf to get to full storage

And in 2006 we will likely get to 3500 bcf, adding 1786 bcf during a summer when the spread averaged $3.96 ! Is it any wonder that users are buying now and putting into storage for winter? It is cheaper now and we should not be surprised that storage will be full.

But, does full storage therefore tell you anything about the long-term supply-demand fundamentals for natural gas? I would contend that is does not.

What you should notice is that the operators who used to be able to buy gas in the summer cheaply can't do that as easily anymore. The winter users now must compete with the summer users, namely the electric utilities that use natural gas to generate electricity, especially when it gets really hot and natural gas-fired "peaking" plants generate a great deal of incremental electricity.

I mentioned that we had an abnormally warm winter last season. To put it in perspective, you should note that winter use of natural gas has a big "fat spot" of use during the 6-week period from mid-December to Early February. Take a look at the data shown here, you'll see that a normal winter would see withdrawals of gas from storage that averages around 900 bcf for this "core" 6-week period. Yet this year, with a record-warm January, we only used 272 bcf:

The point being that we started out with a lot of gas in storage, but only because we had a warm winter. We built to full storage, but only becasue of high prices and an attractive spread. Moreover, if we hadn't had that 700 bcf overhang from a warm winter, we might be sitting here now wondering what type of price it will take to get to full storage.

Once you consider that we can't really predict weather with any accuracy, you must realize two things:

1) Natural gas prices will remain very volatile, and dependent on weather.
2) Storage levels are a weak indicator of long-term prices.

We believe that it requires long-term natural gas prices in excess of $7.00 per mcf in order to generate meaningful returns on most drilling programs in the U.S. This is based on finding and development costs, operating costs, etc., that we won't get into right now. That is later. For now, just be wary of anyone who relies on storage numbers to predict the future.

For those who want to know more about storage, the U.S. DOE has a report titled "Estimates of ...Working Gas Storage Capacity".

U.S. HAS SECOND WARMEST SUMMER ON RECORD

2006-09-15T07:00:00.000-07:00

The period of January-August was the warmest on record (data since 1895). As the graphic above illustrates, it was warmer than normal everywhere, but especially in the middle of the country. Still, the EIA reports that although June was warmer than normal, last June was warmer yet, as measured by cooling degree days; year-to-date cooling degree days through June, though, were 11.7% higher than in 2005.

Whew, it was a hot one! It even broke a hundred degrees in the bay area for a few days. I wonder if people were using their air conditioning...

Peak Oil musings, once again

2006-08-31T14:21:00.000-07:00

This latest article on peak oil: Peak Oil Forecasters Win Converts on Wall Street to $200 Crude prompted me into a discussion with a colleague, the gist of which I post here...

I find the article well-written and fairly balanced...the author at least concedes that both sides have an opinion worth discussing. Moreover, he as assembled in one article many of the most outspoken voices on both sides of the argument and he leaves the reader to make his or her own assessment of who is "right" (maybe both are). On that note, what I always find interesting is that the people who tell us that the peak oil theory is hogwash very often make arguments that do not actually address the initial theory. Such as this quote in the article:

"Alex Cranberg, chairman of Denver-based independent oil company Aspect Energy LLC, calls the peaksters Chicken Littles -- misguided souls who think the sky is falling.

Like many oil-industry vets, Cranberg, 51, says market forces and technological advances will ultimately cure our energy ills. As oil prices rise, companies will be more willing to hunt for crude and extract it. They'll invest in expensive deep-water wells and new technologies to wring more oil from existing fields. Consumers will start conserving energy. Even now, stock market investors and Silicon Valley venture capitalists are pouring billions of dollars into companies developing ethanol, solar power and other alternative sources of energy."

What you should notice is that Mr. Cranberg doesn't present an argument against oil production peaking, but rather suggests that we have ways of getting more if prices stay high and that people will use less. So his argument is more about the price oil of than the volume. I am inclined to believe Mr. Crandall is right, that higher prices will spur supply and decrease demand....however, this still doesn't preclude the validity of the peak oil argument. That is, maybe we can maintain production volumes at a high level, but growing volumes enough to meet demand likely won't happen, even if we don't see a peak just yet. Population growth alone will put too great a strain on the system, and the maturity of existing reserves will ensure that we will fight an increasing production decline curve over the next 20 years. That is the key to the peak oil argument - the law of large numbers in some sense - that at some point your growth makes you too big and the amount of new discoveries can't offset the losses from the older fields in mature basins. The final factor is that while technological advances will allow us to extract our existing reserves faster, those advances may have less impact on extending actual recoverable oil.

The bottom line is what I have been saying for years: we're not running out of energy, necessarily, but we may have run out of really cheap sources of energy. Our way of life has been built on cheap energy, and the U.S. uses more energy on a per capita basis than anyone else. With all that in mind, I believe that the greatest impact we can have on the extension of our finite resources is not on the supply side, but rather on the demand side...and therefore I would suggest that efficiency be our primary policy goal in order to solve both short-term and long-term issues. This does not come free or easily, but we as a society will not start treating energy as a finite resource as long as "thought leaders" keep telling us that everything will be OK if only oil companies would stop acting like capitalists (the only thing that has saved us at this point is pure, not-so-unbridled capitalism).

I would love to find new ways of reducing consumption while maintaining our existing habits (suburban sprawl and long commutes, disposable everything, long-distance travel), or finding truly renewable sources that are economical and scalable. I don't need a single-solution silver bullet -- a conglomeration of many solutions will likely be our end game. Nuclear is key, as France and Japan have figured out. Wind will have a niche, as will solar. Crude oil can be partially displaced in the transportation sector by natural gas or coal by conversion technologies that allow those hydrocarbons to be liquefied (but those solutions carry their own obstacles). And after 30 years of making cars larger and more powerful, maybe our excellent engine technology will turn to creating absolute efficiency gains instead of relative efficiency gains with added power (maybe, but nobody will care if prices drop in their inevitable cyclical manner). Unconventional resources (oil sands, etc.) will grow, of course, but only if prices remain high enough.

Meanwhile, our hydrocarbon lifestyle means that we (as investors) want to own the lowest-cost sources of the stuff, be it crude oil, natural gas, coal, or electricity generation, because until traditional sources are replaced (when?), the last barrel standing will be extremely valuable.

green nuclear?

2006-08-25T06:57:00.000-07:00

Burning ethanol in your car releases CO2

2006-08-11T13:24:00.000-07:00

Every day in the news I hear that consumption of ethanol produces no CO2.

This is of course not true. When you burn a gallon of ethanol in your car's engine, CO2 is released. Ethanol gets fewer miles per gallon than gasoline and so, on a per-mile basis, releases at least as much CO2 into the atmosphere as conventional gasoline. It is true that CO2 will later be absorbed by growing more corn to make more ethanol, and that full-cycle analysis presumably makes ethanol closer to being carbon-neutral (however, see DOE link below). Unfortunately, though, some in the media hear that ethanol is carbon-neutral and then mistakenly state that consumption of ethanol produces no CO2.

Ethanol production and consumption generates lots of CO2. Not a surprise to anyone who pays attention to chemistry or thermodynamics, but it bears repeating so that we can understand that the hopes of sequestering carbon may lie in making sure it is produced at centralized locations. Producing CO2 at the tailpipe of the car, whether from burning ethanol or gasoline, still adds to the carbon balance, regardless of whether the crops later absorb it. Note that we could grow other things to absorb carbon, without then combusting those things, and we would then be carbon negative - which is even better than being neutral.

Just remember these ethanol chemical aspects:

CO2 is released when ethanol is fermented from corn starches:
C6H12O6 + Enzyme = 2 C2H5OH + 2 CO2
The amount of CO2 by molecular weight is roughly equal to the amount of ethanol by molecular weight.

Then, when you burn that ethanol (C2H5OH) in conjunction with oxygen, it produces about twice it's weight in CO2, slighty less than gasoline, depending on other atmospheric conditions:
C2H5OH + 3 O2 = 2 CO2 +3H20

The U.S. Department of Energy published a report on full-cycle CO2 that suggests that even with full-cycle absorption by the relevant plants, corn-based ethanol CO2 output was less than 5% different than from gasoline. So, next time your hear that ethanol produces no CO2, be a wary consumer of that information...

Energy Research Council at MIT

2006-08-11T09:05:00.000-07:00

All sorts of interesting, odd initiatives.

Grain drain.

2006-08-10T20:04:00.000-07:00

Why our modern agricultural practices may very well bear high responsibility for our so-called energy predicament.

Eight years ago (well, not quite).

2006-08-10T19:55:00.000-07:00

At the time, there was worldwide overproduction, weak demand, and slumping prices.

Ethanol impact on natural gas

2006-08-10T09:28:00.000-07:00

I posted this as a comment to a piece by Robert Rapier on his blog R-squared . It is in response to Vinod Khosla's view of ethanol's future. I thought I'd post it here as it ties back to some of our prior comments on ethanol:

Mr. Khosla also appears to skim over the cost and logistics associated with significant increased use of natural gas in the production of ethanol (and as a second-order effect, the increase in nitrogen-based fertilizers derived from natural gas). He correctly states that the energy balance question needs to consider that ethanol production displaces crude oil consumption with natural gas consumption, and that implies an improvement in full-cycle greenhouse gas emissions.

However, he doesn't seem to understand that natural gas production in the United States is declining fast, and that we stand at a peak point not unlike where we stood with regard to U.S. crude oil production in the 1970s. If we continue to increase our demand for natural gas through ethanol production, that will do one of two things: 1) increase our need to import more via Liquefied Natural Gas (LNG) or 2) drive price-sensitive users out of the market, thereby potentially increasing use of coal for electric generation. Neither of these outcomes are much of an improvement over our current crude oil situation.

Mr. Khosla also needs to understand that by increasing our dependence on imported natural gas (historically not something we've had to worry about outside of Mexico and Canada), we're just trading one set of trade partners (Saudi Arabia, Iran, Venezuela) for a new group. Some of the largest natural gas reserves in the world are held by Russia, Qatar, and Iran. I'm not sure that wedding ourselves to these countries satisfies anyone's view of "energy independence".

Natural gas finding and development costs in the U.S. are high and rising. It is a mature province with limited hope for massive new reserves. Foreign sources, by virtue of scale, are vastly cheaper and will necessarily be the choice of source, assuming much of the very expensive LNG infrastructure gets built, which is only a given if gas prices stay high (they will). Because of the massive capital needed, there are few scenarios where we have both low prices AND abundant new imports.

Bottom line: trading natural gas for ethanol probably isn't the best and highest use of those molecules.

I just caught wind of this

2006-07-31T08:40:00.000-07:00

This monday morning, I first read an article in today's Wall Street Journal which said that pension funds are pouring money into wind power as "an alternative source of low-risk, high-yield investment." This took me by surprise, primarily because I didn't realize that wind power was being perceived as a low-risk investment. I saved the article and planned on looking at the topic a little harder later on.

As luck would have it, later on proved to be a few minutes later. In the latest (August 7, 2006) issue of US News and World Report magazine, there is an article speaking on the difficulties the wind energy companies are having with the FAA, et al. Ahh, this is the wind I remember. There is no doubt that more funds are being directed to wind energy, but there shouldn't be any doubt either that there are some significant hurdles to jump before wind energy can be touted as a safe investment.

WSJ article (subscription required): http://online.wsj.com/article/SB115430735542421868.html?mod=DEN

US News article: http://www.usnews.com/usnews/news/articles/060730/7wind.htm

You Don’t Need Oil To Make Fuel

2006-07-25T11:40:00.000-07:00

Coal-to-Liquids (CTL) has always been dabbled with as a viable energy alternative in the U.S.--always concurrent with steep crude oil prices and always dismissed when those high prices for crude subside. Now that the general public is getting acclimated to the notion of a $70+ per barrel of oil world, CTL interest is back.

As this article cites, the main obstacle in producing CTL has always been production cost, which is currently around $35 per barrel. Beyond that, CTL is a cleaner alternative to oil and coal is something that the U.S. has plenty of, which suprisingly pleases lobbyists and politicians on both sides of the political fence.

The link takes you to the Mother Jones website; the article is a commentary from Montana Governor Brian Schweitzer, from November 7, 2005.

http://www.mojones.com/commentary/columns/2005/11/synfuel.html

Ethanol Roadmap

2006-07-13T22:19:00.000-07:00

Here's a report that was recently released by the DOE regarding the plans for adopting ethanol here in the US. It's long, but contains a lot of useful and important information.

Place your bets

2006-06-05T12:18:00.000-07:00

Hurricane season is nearing, and there is now betting action on how many/how severe it's gonna be. According to this blog, the current odds are in line with what one expert predicts. As of this post, the best odds offerred are the likliehood that 2 to 4 class 3, 4, or 5 hurricanes will hit the US mainland this season; they currently stand at 2.5 to 1! By the way, Hurricane Katrina was a class 1 hurricane; the lower the number, the less impact. This chart explains. Class 3 to 5 hurricanes aren't nearly as nasty as Katrina was, but Ivan and Rita were class 3 to class 5, so it can still be severe.

Could you imagine what would happen to GOM producers if they suffer another bad hurricane season? Shell just got the Mars platform nearly operational; what would they do if another hurricane ripped it apart? This is all doomsday/worst-case scenario speculation on my part, but it has to be a constant thought to anybody involved in the Gulf of Mexico.

A study by the National Coal Council

2006-05-17T21:09:00.000-07:00

This is a study published by the National Coal Council for the DOE that came out in March. It contains a nice analysis of the potential for coal in the US, and where global energy demand/supply is headed over the next 20-30 years.

Big Oil's Best Defense Is Simple Economics

2006-05-15T06:09:00.000-07:00

http://online.wsj.com/article/SB114721563123248275.html?mod=article-outset-box

I think this piece by Alan Murray from Wednesday's Journal is spot on. One of the better quips: It's symptomatic that the Arizona resident who complained on the "Today" show about spending $50 to fill his tank was driving an SUV.

Wall Street Journal supports lifting of ethanol tariff

2006-05-09T13:17:00.000-07:00

http://online.wsj.com/article/SB114704795726946244.html?mod=opinion_main_review_and_outlooks

Congressman (R-AZ) Shadegg introduced it, Bush endorsed it, and now the Journal does too. It will be interesting to see where this goes, and how it will impact domestic producers if the tariffs do ease up. Since it's close to election time, I think anything Bush can do to make it at least appear that his administration/republicans are for lowering gas prices, he will do.

Political cat and mouse in Tajikistan

2006-05-08T16:15:00.000-07:00

http://news.yahoo.com/s/afp/20060508/pl_afp/tajikistanussecurity

By itself this story may not seem significant, but it is a small part of a bigger issue. There are plenty of separate interests competing for the same hydrocarbons in the region, and the chess match between competing nations (i.e. United States and Iran) will prove to escalate, if kept at its current pace.

Comparisons through Charts

2006-04-28T09:25:00.000-07:00

I've generated some graphs to illustrate some lesser-illustrated facts about gasoline prices and Oil and Gas companies.

Bureau of Labor Statistics

Yet there is no public outcry against breakfast cereal, no added taxes for successfully selling Cheerios.

Here's another one, showing profit margins across industries (click to enlarge):

This one is from Western States Petroleum Associaton; data from Businessweek and 10-Ks. Sure, the larger O&G companies earn billions of dollars per quarter, but they also suffer billions of dollars in costs, making their margins slim and in line with the average, as this graph depicts. Tech companies, on the other hand, dominate the upper portion of profit margins, yet are applauded (if not encouraged) to do so by the public. Is there a double standard?

A good ethanol article by Ed Wallace

2006-04-28T08:26:00.000-07:00

Ed Wallace has written a very good article in Business Week (Ethanol: A Tragedy in 3 Parts) relating some of the history of mistakes made in the U.S. as we've tried to make ethanol a larger part of our fuel mix. He points out the VOC and smog problems, which are well documented and known to anyone paying attention, but I think the most interesting reminder in the article is the unique position Brazil has been in with regard to sugar crops...a position that we can't hope to replicate given our farming climate in the U.S.

We might be able to improve yields from corn (new enzymes, bio-engineering, etc.), but more likely we have to focus on ways to increase yields from crops which have better starting qualities relative to corn. But so many questions follow from that issue...

If a fuel future based on ethanol doesn't include corn, will the politicians be as interested in pushing ethanol?

If we determine that ethanol can be made competitive based on imported crops other than corn, are we still willing to back it? Would that make us less dependent on foreign oil producers but more dependent on foreign crop producers?

Would we all want to invest in warm-climate farm countries that can grow lots of sugar?

Would Hawaii become the country's most important fuel supplier?

Would the sugar producers of the world form a cartel (SOPEC)?

How to make moonshine

2006-04-27T07:19:00.000-07:00

An interesting note: the creation of ethanol uses the same (or very similar) distilling process as making moonshine, or other potable alcohol drinks. In fact, ethanol producers have to insert an additive to the product before they transport in order to make it non-drinkable, or suffer governmental penalties.

I had a friend that worked in the fuels division on an aircraft carrier, and was in charge of the plant that made the jet propulsion fuel for the aircraft. He told me that it was common for large alcoholic drink companies, like Anheuser-Busch, to recruit guys like him for work when they got out of the Navy. The technology, according to my friend, was almost exactly the same, so it makes sense that it works the other way around as well. I wonder if guys working at Budweiser are getting pulled away to make ethanol...

***UPDATE***CNN Video on this topic: http://www.cnn.com/video/partners/clickability/index.html?url=/video/us/2006/04/27/snow.shift.to.ethanol.cnn

Ethanol and the Energy Balance question

2006-04-26T16:22:00.000-07:00

Ethanol and the energy balance question; is the flaw in David Pimentel's method?

The more research I do into the actual full-cycle cost of producing ethanol, the more I realize that there are simpler ways of looking at the energy-balance question. That is, I have read many quality analyses that include the costs all the way back through the corn production (see the Feb 13, 2006 blog entry below). These include the cost of fertilizers and fuels that are hydrocarbon based and some argue that when all the energy is taken into account, that ethanol is either 1) a net negative energy suck, or 2) extremely inefficient compared to other alternatives.

However, the analysis of the cost of the inputs to the ethanol process do not need to go back this far, back beyond the first-order costs of the inputs. We can stick to just the first-order costs as long as we can know and analyze their true, unsubsidized value -- that value which allows for a market-based return on capital.

Let me illustrate by example: If you are looking at the cost of making a shoe, your cost analysis may consider the cost of leather purchased in an open market at arm's length. You don't go back and assess the cost of feeding the cow, tanning the hides, etc. This is because the cost of the leather that is sold to the shoe manufacturer is PRESUMABLY being sold at a value that recaptures all the upstream costs plus a return on capital for the leather manufacturer. If the shoe manufacturer can take the leather and increase it's value by adding labor and capital and create a product which the market will purchase at a price that provides profit, then it all works. This is an obvious statement in a capitalistic system, but is important to note when we consider all the ways in which the government makes this analysis less-than-transparent in the case of ethanol.

So, to my point: the ethanol energy balance debate can be put aside if we ignore subsidies for corn in the U.S. as well as any tariff impact that keeps out or increases the delivered cost of otherwise lower-cost imports. We can use this unsubsidized corn value (including a profit margin) as the valid input for analyzing ethanol's economic viability.

This allows us to concentrate on analyzing the opportunity for efficiency gains in the ethanol production process itself without getting bogged down in the upstream issues of whether we are capturing all the hydrocarbon costs of producing corn (or sugar). That said, we have to understand that the price of those inputs will fluctuate with fuel costs, but that analysis is fairly easy and can be the subject of a sensitivity analysis. It will then inherently take the true full-cycle energy-use balance into account.

Of course this ignores one still-valid point, that an all-ethanol world (no such thing) doesn't stop us from needing some amount of hydrocarbons produced either domestically or from abroad in order to grow the crop that makes the ethanol. But think of it this way: if we ran all our cars on ethanol, it would be true that CARS would no longer be the primary users of hydrocarbons like crude oil. Now it would be the CORN industry that was using all the oil. It would then be up to that industry to find ways to reduce their input costs or their "addiction to oil".

Where would that buck stop?

-Dave

Gas Tax - The Unspoken Factor

2006-04-26T07:15:00.000-07:00

What determines the price of gas at your local station? It isn’t just the price of a barrel of crude oil. By far the biggest factor in determining the price at the pump is the taxes—or subsidies—that a government levies on gas. In Venezuela, a state that subsidizes prices, a gallon of gas only sets you back 15 cents. In Germany, however, a state that taxes gas heavily, a gallon costs $5.53. So, how far you can go with $20 of gas depends on where you start your engine.

From Foreign Policy, March/April 2005.

Holographic Solar?

2006-04-25T17:47:00.000-07:00

Prism Solar Technologies of Stone Ridge, NY, has developed a proof-of-concept solar module that uses holograms to concentrate light, possibly cutting the cost of solar modules by as much as 75 percent, making them competitive with electricity generated from fossil fuels.

The link takes you to the full article. From the MIT Technology Review.

Energy Companies Choose Nuke Plant Site

2006-03-16T13:46:00.000-08:00

Duke Power Co. and Southern Co. have selected a site in South Carolina for a potential nuclear power plant, which would be one of the first ordered in the U.S. in more than 30 years, the companies said Thursday...The industry has been ramping up its nuclear program after President Bush signed an energy bill last year that enhances incentives for building nuclear reactors.

Wind Energy - Annual Industry Rankings

2006-03-16T09:31:00.000-08:00

The American Wind Energy Association (AWEA) just released their annual rankings for the wind energy industry in America. Some interesting points:

California still has the most capacity installed, but Texas has made serious gains from last year and is expected to overtake California this year; this makes sense, because Texas has the second-most wind energy potential behind North Dakota.
Xcel Energy, which operatates in Minnesota, Colorado, and Texas, has replaced SoCal Edison as the top buyer of wind power. SoCal Edison has sat atop this perch for many years but with the surge in Texas, Xcel has been buying away, with plans to greatly increase their wind energy consumption in Colorado as well as Texas in the following year.
This chart displays the installed wind power capacity in the US:
(Chart removed for space considerations)

The Growth of Renewable Energy: Jan 2005 to Jan 2006

2006-02-22T12:40:00.000-08:00

Click on the map to take you to the website that shows an animated picture of the change in renewable energy in the US from 2005 to 2006. From the Global Energy website.

Wind Power In Spain - from MIT Technology Review

2006-02-21T14:14:00.000-08:00

Technology Review magazine from MIT is running an 8-part special advertisement in partnership with the Trade Commission of Spain. The series will highlight new technologies in Spain. First up, Spanish wind power. The link will take you to the special segment on Spanish wind. From December 2005/January 2006 issue.

Corn-based Ethanol still net energy balance negative

2006-02-13T09:02:00.000-08:00

Continuing on the alternative energy theme, here is a report from David Pimentel, professor of ecology and agricultural science at Cornell University. Dr. Pimentel's thesis suggests that the energy cost of producing corn-based ethanol outweighs the benefit. Another concern he has is the amount of land required; from his research, it takes 7 times as much corn cropland to fuel one car than would be needed to feed one human.

Keep in mind that this article is from the Hubbert Center for Petroleum Supply Studies (Colorado School of Mines) and that it might be a bit biased. Also, it was published in 1998 so some of the cost structure included in the report is outdated. I think the gist, though, still holds true. On the flipside, the National Ethanol Vehicle Coalition (http://www.e85fuel.com/e85101/faqs/energy.php) maintains that this is a "common misconception."

Canadian Wind Energy doubles capacity

2006-02-10T09:52:00.000-08:00

The Canadian Wind Energy Association (CWEA) just released that 239 megawatts (MW) of wind energy capacity was created in 2005, up from 122MW in 2004. Robert Hornung, president of the CWEA, says that a MINIMUM of 500MW are slated to be established for 2006. As this map shows, there is much wind energy potential along the western and eastern coastlines of Canada. Canada is currently ranked 14th in global wind production, with 682MW installed as of January 2006.

In comparison, the US installed 2500MW in 2005, with 3000MW slated for 2006. 9149MW are currently installed. Canada is installing turbines at a greater velocity than the United States, but are obviously far behind compared to the US and others, like Spain and Germany.

Across the globe wind installation has ramped up considerably, primarily due to the price of gas, which makes wind energy a viable alternative at these prices. Still, if you take away the government-sponsored incentives that are compiled into the cost structure of these projects the return isn't attractive for widespread investment.

CWEA website: www.canwea.ca
American Wind Energy Association (AWEA) website: www.awea.org

CTL info

2006-02-01T21:45:00.000-08:00

This is a terrific paper out of Princeton comparing direct vs. indirect CTL technologies. It's a couple years old (Dec 2003) but very educational and informative. It's very supportive of indirect F-T for CTL, especially in producing methanol and dimethyl ether (DME).

Ethanol in Brazil

2006-01-09T20:22:00.000-08:00

Interesting article from the WSJ on Brazil's success in using ethanol as a replacement to gasoline. The development of a fuel-flexible engine makes a lot of sense. F-T diesel could be to the US what ethanol is to Brazil...producing ethanol in the US would likely come from corn, which this article points out, is more costly than using sugarcane directly.

What a shock...the price of oil is going up

2005-12-20T11:07:00.000-08:00

With finding costs like these, is it any wonder that steadily increasing global demand is driving up the price of oil? This isn't exactly a 4,000ft Permian Basin well.....

http://www.bloomberg.com/apps/news?pid=10000082&sid=anSCGi0.P5LU&refer=canada

Fischer-Tropsch diesel

2005-12-17T21:21:00.000-08:00

Interesting article on F-T diesel. I'm amazed at the extremely low aromatic content of the resulting fuel (<3%), which is key to reducing soot/UHC emissions. And the high concentration of parafins gives the fuel a nice, high cetane number. However, in producing gasoline, they'll need to reduce the level of parafins in order to boost the octane number, but this isn't difficult.

HYDROgen still requires HYDROcarbons

2005-12-12T14:48:00.000-08:00

Whenever I get into a discussion about high oil prices with someone who is disconnected from the energy industry, I inevitably hear about hydrogen fuel cells and how we can "replace fossil fuels". I know the subject will come up over the holidays when I get together with my much-enlightened "green" family members. So, it is important to remind ourselves of the cogent facts on hydrogen, which Donald Anthrop did so very nicely last year in a paper published by the Cato Institute. It bears reading again...especially as it is a good reminder of why I am so positive that natural gas will be a huge part of our ongoing energy picture. Here's the link:

http://www.cato.org/pubs/briefs/bp90.pdf

Early Release of EIA Annual Energy Outlook

2005-12-12T07:52:00.000-08:00

The Annual Energy Outlook presents a midterm forecast and analysis of US energy supply, demand, and prices through 2030. The projections are based on results from the Energy Information Administration's National Energy Modeling System. The Early Release includes the reference case. The full publication, to be released in early 2006, will include complete documentation and additional cases examining energy markets.

http://www.eia.doe.gov/oiaf/aeo/index.html

http://www.eia.doe.gov/oiaf/aeo/pdf/earlyrelease.pdf

Will industry play an active role in clean energy?

2005-12-08T17:17:00.000-08:00

Historically, when it came to cleaner emissions standards, government has led the charge. Business, on the other hand, has typically balked at the costs associated with compliance; the debates over legislation pertaining to clean diesel and mercury emissions come to mind. But industry's staunch opposition to "clean energy" may potentially be softening. General Electric, led by CEO Jeffrey Immelt, has a new idea: instead of resisting green energy, profit from it. Whether it's a real shift in priorities or simply timely PR remains to be seen, but if the economics make sense for GE, perhaps we are closer to the inflection point where industry can go greener (a very relative term) without going out of business.

The following is from the December 10th, 2005 edition of The Economist (see the whole issue for more):

"NEXT month General Electric's corporate bosses will drop a bombshell on the hard-charging managers of its global businesses. In future they will be judged not only by all the usual measures, such as return on capital, that investors typically care about: they will also be held accountable for helping to save the planet.

Every GE business unit will have to cut its emissions of carbon dioxide (CO2), the main greenhouse gas (GHG) behind global warming, by a different target. Energy-intensive divisions such as plastics and locomotive manufacturing will need to make big cuts in emissions, while the paper-pushers at the group's financial-services divisions will be told to aim at smaller, but still ambitious, cuts.

GE's new goal is to cut its overall GHG emissions by 2012 to 1% below their level in 2004. That might not sound ambitious, but if no climate policies are enacted, the company's projected revenue growth would increase its GHG emissions by 40% above 2004 levels. The firm also vows to cut the intensity of its GHG emissions (that is, the amount of GHG emitted in terms of its economic activity) by 30% by 2008. By comparison, the UN's Kyoto Protocol calls for Europe to reduce its GHG emissions by 2012 to 8% below the 1990 level and George Bush's voluntary climate scheme calls for an 18% cut in America's GHG intensity from the level in 2002 by 2012.

The new campaign makes some extravagant promises. The company vows to double its revenues from 17 clean-technology businesses, ranging from renewable energy and hydrogen fuel cells, to water filtration and purification systems, to cleaner aircraft and locomotive engines. This would take such products from $10 billion in sales in 2004 to $20 billion by 2010, with more ambitious targets thereafter. To get there, Mr Immelt has promised to double research spending on clean products, from $700m per year to $1.5 billion, by 2010. (GE's total research expenditure was $3.1 billion in 2004 and its revenues were $152.4 billion.)

Most striking, however, is GE's new position on climate change, an issue that divides corporate America. Some large industrial groups have long argued that the climate problem is real. Three dozen such big firmsÂincluding DuPont, United Technologies and WhirlpoolÂhave been united by the Pew Centre on Global Climate, a non-partisan charity, to lobby for action by America's federal government to curb CO2 emissions. Many others, notably Exxon-Mobil, but also much of America's coal-burning utility sector, have remained deeply opposed to any such effortsÂas has President Bush. Awkwardly, many of those utility firms are GE's customers.

Mr Immelt is so convinced that clean technologies will be the future of GE that, invoking the colour of American money, he has made his new mantra: Âgreen is greenÂ. If he is right, then not only will GE benefit, but businesses everywhere will have to follow in its tracks in one form or another. If he is wrong, Mr Immelt will have led one of the world's biggest and most powerful companies down a dead-end, and the cost to its reputation, if not its financial performance, is likely to be huge."

CERA's arument against "peak oil" requires natural gas...

2005-12-08T07:01:00.000-08:00

http://www.finfacts.com/irelandbusinessnews/publish/article_10004190.shtml

So here we have CERA saying that guys like Matt Simmons and Tom Petrie are overstating their "peak oil" arguments in that they aren't accounting for new NGL and GTL based fuels that will add to our fuels mix. Here's the problem: The peak oil proponents never said there weren't OTHER ways to get energy or create fuels for our cars, they are merely pointing out that crude oil itself may be nearing its productive peak. Bringing in GTL and NGLs into the equation, both derived from natural gas, doesn't prove the peak oil guys wrong. As a matter of fact, I believe that is part of their thesis...that we need to look for new ways to derive energy from all hydrocarbon and non-hydrocarbon sources.

Canadian Gas Shales to follow the CBM path?

2005-12-07T09:58:00.000-08:00

The U.S. natural gas market has developed coal bed methane (CBM),.k.a. natural gas from coal (NGC), a number of years ahead of the Canadian oil and gas producers. But now Canada is moving very strongly into CBM/NCG in both the Horseshoe Canyon and Mannville plays. With the major improvement in gas recovery from shale deposits in the U.S., and the "hot" plays going on in the Barnett Shale, as well as the Fayetteville, New Albany, Caney, and Woodford shales -- how far behind will Canada be? Is there another major gas deposit waiting to be developed by the early movers in the Western Canadian Sedimentary Basin? Check this link. I'd be curious about any geologist's point of view on prospectivity in Canada's gas shales:

http://www.gastechnology.org/webroot/downloads/en/4ReportsPubs/4_7GasTips/Winter04/GasPotentialOfSeclectedShaleFormationsInTheWesternCanadianSedimentaryBasin.pdf

BTW, welcome to my blog...