Dave's Energy

Wednesday, October 17, 2012

Stacking Oil Barrels to the Moon

As a follow-up to my prior post helping to visualize the scale of the world's daily crude oil production, I wanted to provide another "scale" eye opener I often use around the office:

So you have realized now (by reading this post on daily oil production) that we produce enough oil each day such that stacking that production in barrels would reach the moon every 5 days.  But do you really appreciate just how far away the moon is?  Let' use an example to illustrate... and here is where I usually ask someone to draw me a circle representing the Earth, then I ask for another circle representing how big the Moon is in comparison (this usually provides some good fun discussion). The typical answer I get is fairly close, something that looks like this:

In reality, the moon's diameter is about 2160 miles and Earth is about 7926 miles, so the Moon is a bit more than 1/4 the diameter of the Earth, (but it's volume is about 1/50th the Earth).  So the 2-dimensional view to the left is fairly close to correct, at least as far as relative size goes.


But then I ask this: "Can you draw me something more to scale now, showing how far the moon is away from the Earth?"  

I get all kinds of answers, many which look much like the drawing above - they don't change the distance between their drawings and might say, "probably about like that":

So I ask: "You are telling me that if I were to "flip" your flat moon over once, it is close enough that it would touch the Earth after just one flip? You are saying that the Moon is just "one moon-width" away? That usually causes them to re-draw it, maybe moving the Moon over about the distance of one or two Earth diameters.

And while that may seem a good distance, the reality is that the moon is much farther away.  At an average distance of about 238,900 miles from Earth, and with the Earth's diameter being 7,926 miles, that means the Moon is about THIRTY (30) Earth diameters away, or about ONE HUNDRED TEN (110) "Moon-diameters" away.  I then like to draw something on my white-board that looks more like this:



Sometimes my full-wall white board isn't big enough, unless I make sure I draw the initial Earth circle small enough.  Either way, I have to move across the room to finish the drawing. And then I stand back dramatically and let them absorb that and say: "That is how far away the Moon is,   and every five days we stack that much oil up. NOW do you understand just how much we produce every day in this world?.... Crazy, huh?"

Then I challenge them to find me another industry that comes even close to that..."Anyone?.... Anyone....?"

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Tuesday, October 16, 2012

How to Visualize What Daily Oil Production Looks Like

I get in all kinds of discussions in various venues about alternative energy. The latest Presidential debates have people talking about various alternative energies and energy independence. As I always say with alternative energy, the first thing one has to ask is "alternative to what?" If you are talking about transportation fuel (gasoline and diesel), then you are looking for an alternative to crude oil and a new way to fuel the transportation market. If you are talking about the electricity generation (power) market, that is another subject entirely. leading to how to displace coal as our top generation source (while the power sector also uses nuclear, natural gas, solar, wind, etc., coal generates close to half our electricity).

For the transportation (crude oil) sector you have heard my prior posts discuss why it is hard to displace crude oil with any ONE solution. Still, many people I talk to have a hard time understanding that many alternative solutions cannot SCALE large enough to displace oil, because realistically the amount of oil we produce every single day is so massive that it is hard for people to get their heads around it. So in order to get people to visualize just how much oil we produce every single day in the world, here's a quiz I used to like to give potential interns:

We produce and use 90 million of barrels of oil EVERY day in the world. If you stacked those barrels on top of each other, how many days of production would it take to reach the moon? 1, 10, 100, 1000?

The answer might be derived in this manner:

1) 90 milliion barrels x 3 feet (approx) height per barrel = 270 million feet tall (one days' production)

2) 270 million feet / 5280 feet per mile = 51,136 miles of production each day

3) Miles from the earth to the moon: approx 238,837 / 51,136 per day = 4.7 days

Resulting answer: about 5 days to reach the moon

So, if you want to replace oil with some liquid fuel derived from algae, corn, etc,, you have to find something that you can stack to the moon every 5 days and do that every day, all year long with no disruptions. Hard to do.

EDIT: Now you can go to my next post titled "Stacking Oil Barrels to the Moon" and see if you really appreciate just how far away the Moon really is.

Does that sound like a great deal of product? It should... Put another way: we speak about oil production in terms of barrels per day because if we talked about annual production the numbers are astronomical:

90 million barrels per day times 365 days a year equates to over 32 BILLION barrels each year (an oil barrel is 42 gallons so that is 1.3 TRILLION gallons of oil).

To yield something like that from any other naturally occurring source of energy is extremely difficult. And to top it off, those barrels of hydrocarbons are VERY energy dense. You can pack a lot of energy into a gallon of gasoline or diesel, which are very portable with today's infrastructure. Portable, dense, abundant. Hard to replicate that for now. That is why there is no ONE solution.

Which is why efficiency is the key, and electrification of the auto allows that while it diversifies the source of the power in front of the electrical plant. See my prior post titled: "The Best Alternative Fuel"

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Saturday, July 28, 2012

What the politicians and media call "Big Oil Subsidies"

I am so very tired of political misinformation. Mostly, I brush it off as easy to spot, figuring that the more enlightened citizens out there will recognize BS for what it is. But that doesn't seem to be the case when it comes to oil companies. And this rampant BS is especially prevalent in election years! People want to believe any lie that is thrown out there.

Case in point: My brother Jeff is as intelligent, educated, and logical as any man as you'll ever meet. Yet even he fell victim to the perpetual lie about oil company "subsidies". He recently said something to me like: "I really don't see why the big oil companies should get special tax breaks that others don't get". I realized then that the lies are so deeply ingrained in our collective minds that I may never change anyone's mind. Yet, I did manage to sway my brother once he was informed of the real facts. So while this may be an uphill climb, I will embark on an adventure here and try really hard to give the basic facts to help some of you realize that the big oil companies don't get huge "special breaks".

 First off, for the short cheat-sheet version of my story, I will point out two key items:

1) The "subsidies" many politicians and media types like to talk about are what every other industry calls deductions for "Cost of Goods Sold". Removing those so-called "subsidies" for the oil business is like saying that car companies can't deduct the cost of steel or labor.

2) The Oil Industry is the second largest taxpayer in the U.S., right after the financial institution sector (another hated industry!)

OK, more detail:

"TAX BREAKS"
If you search the internet for "oil company tax subsidies", you will see the same type of data thrown out over and over "oil companies enjoy huge tax breaks and are big lobbyists". First off, those two statements are intentionally inflammatory and purposefully vague in their connection. But moving beyond that, you often see a few data items thrown about, such as: "$24 Billion dollars in tax breaks" that Senators were debating earlier in 2012. They also like to say things about the massive profits these companies make (they don't tell you, however,that those massive profits are in fact, AFTER taxes are paid).

For now, let's focus on these "tax breaks" that every media outlet quotes...where they tend to perpetuate each other's numbers and make them seem valid merely by virtue of repetition. Typical of the hyperbole is what you'll find on the website of Senator Robert Menendez (NJ).  The $24 BILLION dollars in "tax breaks" that Senator Menendez was railing against in his "Repeal Big Oil Tax Subsidies Act" are in fact the COSTs of drilling wells and the Depreciation (depletion) expense that is deducted when each unit of production is sold.

 For specific wording of what Sen. Menendez was trying to repeal, read the actual Act at the Library of Congress:
http://thomas.loc.gov/cgi-bin/bdquery/z?d112:SN02204:@@@D&summ2=m& 

Where it says the intent of the law: "Limits or repeals certain tax benefits for major integrated oil companies 
(1) the foreign tax credit; 
(2) the tax deduction for income attributable to oil, natural gas, or primary products thereof; 
(3) the tax deduction for intangible drilling and development costs; 
(4) the percentage depletion allowance for oil and gas wells; 
(5) the tax deduction for qualified tertiary injectant expenses. 

Number one should be obvious. If you paid tax on income in another country, the IRS generally lets you deduct that as a business expense. Every industry gets this, so taking this away is not repealing a "special tax break". It's merely allowing for double taxation on the oil companies. Why? Because in the minds of the Bill's authors- they can afford it!

Number two, three and four are tax deductions for expenses incurred in developing and producing oil and gas. For example, "intangible drilling costs" include those items that do NOT get capitalized on the balance sheet as an asset when drilling a well. These are items that get expensed during the process, such as LABOR, MATERIALS, and ENGINEERING. Yeah, those are costs of doing business. Allowing for their deduction isn't a special break, it merely has a different name than the accounting books of a retailer, for example. Calling that a special break would imply that a deducting the labor costs for Starbucks' counter employees is a "special tax break" for Starbucks. In the case of the oil companies, these are the core expenses for producing oil and gas. "Percentage" depletion" is what other industries call "depreciation"  It is the loss of value by virtue of something being produced. In the case of an oil company, that depletion "expense" is the delayed recognition of the costs  that WERE capitalized on the balance sheet when drilling a well (apologies to non-accounting types, but when I say they were "capitalized", that means they were not taken as a deduction at that time, but instead were listed as an asset - there was no tax shield at the time they incurred those costs).  In other words, those were any costs that were not deducted at the time as "intangible".  The oil company is recognizing the costs that were spent to create the well, and taking that deduction on a per-unit basis as they produce each unit of oil or natural gas.  Bottom line: these are actual costs, nothing fancy.  They either deduct them at the time incurred or later when the units of oil are produced.

Number five is a special sub-category of the others - it sounds like some special deal, but "tertiary injectant" merely means the company is injecting something into the ground to cause more oil or gas to be produced. Tertiary is the stage of production after "primary" (when oil flows freely by virtue of its own pressure), "Secondary" (when things like pumps are used to bring the oil to the surface), then "tertiary" (when they use any esoteric means they can to get more oil out). Squeezing out the last of an already-discovered field is called being efficient, and the government should encourage doing so. Taking away a basic cost deduction would be folly and could encourage the abandonment of otherwise productive fields. Another subject, different day: I love how these politicians act as if taking away these "subsidies" would somehow make YOUR gasoline costs go down. Quite the opposite.

In the car industry, should we ignore the cost of labor to build the car, the cost of steel, and the depreciation on the capital equipment (the factory) that the company uses to build the cars? Of course not!! What you would end up with is essentially a "revenue tax", not an income tax.

Oil Company Taxes Paid 

 A few years ago, I wrote this blog post, entitled:
Energy companies pay the most taxes amongst the S&P500 

Where I presented this data (note that these numbers are in millions, so that number below is 90 Billion in cash taxes for the oil companies in 2008, fully 30% of all cash taxes paid by the S&P500 companies.):
The data has changed a bit, but all the relationships stay the same in 2009-2011. Energy companies pay some of the largest absolute amounts of taxes, and at a higher RATE, even after "deductions and subsidies" than almost any other industry.

So next time someone tells you that big oil companies get "special tax breaks", ask them which tax break they are referring to. Then ask them what industry in the U.S. pays MORE in taxes, either at higher rates or in absolute dollars, than the U.S. oil industry. Go ahead, ask.... the answer will be vague, they'll start talking about lobbyists and cronies. They won't have an answer because the fact is they are merely parroting the media hype. Don't be a parrot.

By the same token, don't listen to me either...do your own research and come to your own conclusion. The only way we have a good democracy is through an educated populace.

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Thursday, March 29, 2012

Switching from Coal to Natural Gas: Will It Impact Natural Gas Prices Near Term?

With historically low natural gas prices today, the argument continues to go that low prices will self-correct. My prior post "Explaining the Disparity Between Oil and Natural Gas Prices" discussed the supply side of things and why gas prices won't rise simply due to price-based changes in supply.

Most industry professionals and natural gas producers will tell you that they themselves only see prices rising once we have a significant demand response to low prices. My prior post discussed some of the reasons that fuel switching was no longer as big a deal as it may have been historically. But the main long-term demand response (fuel switching) that can, and will occur, is the displacement of coal fired electric generation capacity with natural gas fired capacity. This is nothing new. It was the standard future view back in the late 1990's early 2000's when gas was last at this low price range of $2-$3/MCF (mmbtu). But, when gas demand outpaced supply, prices went up in the 2003-2008 period and the conversations all started to shift to renewable energy (solar, wind). Now with low gas prices and ample supply we are again back to gas as a "bridge" (albeit a long one) to a more renewable future. The question then becomes whether switching to gas from coal will have a significant near-term 1-3 year impact on natural gas prices. I will contend the answer is no.

First note that moving to gas from coal is not really "fuel switching" - that is, the power producer doesn't just change the fuel in the plant, they build a new natural gas plant and retire or reduce the use of the old coal plant. For this reason, it doesn't happen quickly and therefore doesn't have a rapid-demand-response impact on pricing.

So let's take a look at how much additional gas demand might come from the current plans for building new plants and how much might come with a big push to retire old coal plants.

First off, here is a chart that shows the existing electric generation capacity in the United States, by fuel type. All data is from the Energy Information Administration (www.eia.gov):



Note that although we have more natural gas capacity than coal, we generate more electricity from coal (see chart below), because those plants are typically "base-load" capacity (run continuously) while many gas plants are used to generate peak power(intermittently turned on to meet peak power needs). The chart below also shows the historic rise in natural gas as part of our mix, and the drop off in coal during the most recent economic downturn. Natural gas has increased through both high and low price environments, because it is a better fuel (cleaner, more efficient). With low prices for the foreseeable future, that market share increase can improve even more. And with potential carbon legislation, gas will be significantly favored over carbon-heavy coal.



Now here is a table showing all the planned electric generation capacity additions (as of Nov 2011) through 2015:


Based on the planned additions, the electric generation mix is not expected to change much through 2015. Natural gas will add 37,718,000 MW of capacity, which is 8.1% growth over the existing 467,214,000 MW of existing capacity. Coal grows 2% while wind grows 39% and solar would grow a whopping 840%. When all is done, however, solar is still less than one percent of all generation, and natural gas only moves from 41% to 41.5% while coal drops from 30.1% to 29%.


So how much more natural gas demand might come from that 8.1% increase in capacity? Well, existing gas demand in 2011 for electric generation was 7,600 Trillion Cubic feet (TCF), or approximately 20.8 BCF per day. Simply, let's assume an 8.1% increase to that, and we'd be using an additional 1.6 BCF per day by 2015. The number would likely be higher, because the new capacity may be more fully utilized than existing capacity, which includes a lot of "peak" plants. So let's assume a number more like 3 BCF per day additional demand from electric generation. That's a meaningful amount of gas, but compare that number to the continued growth in production as discussed in my prior post:



You can see that 3 BCF of additional demand isn't going to make enough of a difference, given that we are producing 10 BCF more each day than we were just a few years ago.

The holy grail of changes to gas demand would come from retiring much of our aging coal plants infrastructure with gas plants. Below is a "heat map" from Platt's (McGraw-Hill) showing that much of our existing coal capacity is from plants over 40 years old.



If we retired a quarter of the oldest plants in the U.S., and replaced them with gas at a level that represented about 10% of our electricity mix, that would likely increase gas demand by an aggregate of close to 10 BCF. That would have a meaningful impact on gas prices, and would generate a significant improvement in our emissions profile. But even with a move up in prices, let's say back to a normalized $6/MCF, gas prices are still attractive to the power generator(demand). They also then become more attractive to the gas producer (supply), and we would see even more supply being developed. So we shouldn't fear higher gas prices...that is what would make the move to natural gas a sustainable one.

How soon can we make a move like this? I contend not in the 1-3 year time frame. But to some extent that is dependent upon how much of the excess gas plant "peaker" capacity could be re-purposed for baseline usage and how much new capacity would have to get built - starting right now.

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Thursday, March 08, 2012

Explaining the Disparity Between Oil and Natural Gas Prices in the U.S.

My good friend Ray Conley at Creekstone Capital pointed out the continuing divergence of the market prices of crude oil and natural gas. Being a brilliant math guy and investment guru, Ray knows that statistical aberrations rarely last long and typically are subject to mean reversion. In the case of oil and gas prices, there should be, in the long term, some energy equivalency that keeps their respective prices from continuing on a divergent path. I agree with Ray, in the long term, but I also discussed with him some of the factors that can (not necessarily will) keep the price of oil and natural gas at an "unnaturally" wide spread.



None of this discussion will sound unfamiliar to most hard-core energy guys, but for the sake of other readers, I will just point out a few well known factors driving the oil and gas business right now. I start out by cautioning against the assumption that the price spread shown in the chart above MUST revert to the mean in any short period of time. No doubt there is an argument for energy equivalence: that each commodity is merely used to produce energy and they are therefore "substitutes" from an economist's point of view. But that economist perception ignores some key differences, which are becoming more prevalent.

First of all, to point out the most obvious factor, crude oil is used to make gasoline and diesel and is primarily tied to the transportation needs of the world. There are other marginal uses to produce power and heat (fuel oil) but these are relatively small markets. Natural gas, on the other hand, is not used for transportation fuel - it is used to generate electric power, for residential use (heating, hot water, etc), and as a feedstock for industrial purposes (plastics, chemicals, etc).

About 10 years ago, there were more industries where the two fuels were, at the margin, substitutes for each other. They were/are substitutes mainly in industrial applications where firms can switch their dual-fuel boilers between the two, and for some power producers that could burn either fuel in a power plant.

Historically, that was a big deal when 1) there was less natural gas supply, and 2) industrial use was a bigger part of gas demand. That isn't the case anymore, highlighted by these charts from Nader Masarweh and the California State University - Sacramento Energy Research blog , shown below. Note that there is more total natural gas now (a great deal more), that supply has grown dramatically faster than demand, and that the power sector has become the more important (larger) user. The power sector is a more "sticky" user that doesn't switch fuels based on price, so price divergence between natural gas and crude oil takes on less meaning in today's world. Take a look and then read on below...





Further, I would argue that any fuel switching based on price may have occurred already, based on the divergence of price over the last 2 years. Once all the switchers had done so, the two prices are free to diverge even more so as they would no longer be tied.

And, in the end, crude oil is a transportation fuel that has its own demand and supply curves. And Nat gas is a power fuel that also has its own supply and demand curves. Each will likely work independently to ultimately get the differential to close the existing gap, but not because it MUST, just because crude oil is high and forces are working on demand and supply and because gas is cheap and forces are working there, too. However, those are long term movements. The power sector will continue to increase their use of gas because it is cheap, clean, and plentiful. Many coal plants will be replaced. It could take years before the demand catches up to our new gas supply capacity. Every gas company I talk to has years of wells in inventory they can drill quickly if and when prices rebound, so although low prices are certainly already working marginally on the supply side, we have gotten so good at creating new gas wells at low cost that supply can expand fairly easily if prices start to rise again. I believe it will take a large push on the demand side to really pull gas up hard. That will take years for the long-term balance....or a severe winter where we strain our short-term capacity and drain existing storage.

Another reason many companies continue to produce gas is because they are producing natural gas liquids with it. The value of the liquids stream (propane, ethane, etc) is tied closer to oil prices or to other industrial / chemical demand (as in ethane). These companies will point out that even when their dry gas is just $3.00, the overall value of an mcf of gas includes the liquids that also get extracted, so they really get more like $5 per mcf produced. That is why they keep producing. The same goes for oil drillers in places like the Bakken, they are getting gas as a by-product, and starting to now sell it rather than flare it. A good Bakken well can put off 1-2 million cf of gas a day (2000 mcf). That is the equivalent of a good Marcellus shale gas well with a drill cost of $2mm...and the Bakken guys are getting it for free. With 200 rigs in the Bakken drilling 6 or more wells each a year, that alone would bring on enough gas to replace the 100 gas rigs that might drop out this year.

Meanwhile, companies like Chevron and Exxon continue to increase their production of natural gas, in part because they are learning to improve their shale gas techniques here in the U.S. in order to then transfer their knowledge to international locations where natural gas is very much in need, and selling at far higher prices. The gas market used to be dominated by the independent producers, who ramped up and slowed down drilling very quickly based on price changes. But you can bet the big guys react differently, and far more slowly, to price signals. Another reason gas prices won't revert as quickly in today's world.

So, will the chart revert to the mean? Probably, but it may take time. And the "new mean" may be something very different than the old mean...if you will allow me to play a bit loose with those definitions ;-) And when that happens, I believe we will more likely see crude oil come down, not gas come up. In 2008, I pointed out that we had finally turned the corner on gas production, and my investments started to avoid gas that summer added natural gas puts to take advantage of gas price drops. What I see now in oil is similar - we are creating more new oil supply than ever here in the U.S., and the technology is improving. The difference is that worldwide oil demand is something I continue to see growing, and I believe the new oil right now in the U.S. must replace all the dwindling supplies elsewhere (OPEC and Mexico, North Sea). I think this means we are still in an $85+ oil world, with spikes above that, and that U.S. production will grow, international demand will grow, and the U.S. will become less of an importer, at least in the next 4-5 years. This will dramatically help our trade deficit and I think it bodes quite well for our U.S. economy. The caution I advise, though, is that oil from formations like the Bakken, Eagle Ford, and Niobrara, may be more rare than the natural gas shale plays that have created an oversupply situation. A subject for another day: natural gas is actually being produced out of shale formations, while Bakken oil is actually being produced out of tight formations that are sandwiched between shale formations. Then there is another type of play whereby you "cook" oily shale, which is a different process altogether. Another day, perhaps...

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Thursday, January 26, 2012

Honest Data on Tax Rates Paid by Millionaires

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.

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Thursday, October 20, 2011

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

Tuesday, October 18, 2011

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

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.

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Tuesday, October 04, 2011

What's a Bakken Shale well worth?

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.

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Friday, May 13, 2011

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

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.