• In late February, WZR spudded its Kurdamir-3 appraisal well.
• 3 more wells will be drilled this year in the Garmian block.
• High-impact exploration is about to get underway in the Baram and Hasira prospects.
• Baram-1 could prove to extend Kurdamir discovery into the Garmian block—making it one of the world’s largest.

Dear OGIB Reader,

There are two trends in the Canadian energy patch in the last three weeks that have been making money for investors – but the question is, do they have legs? Can the uptrends continue?

The first and most obvious is natural gas. After doubling in price between April 2012 and November, it dipped down to $3.20/mcfcompanies usually convert gas production into oil (thousand cubic feet) in early winter. The winter just wasn’t as cold as normal… though colder than last year.

But fast forward to March 2013 and colder weather has gripped much of the high population areas of the US east coast and the Chicago area. US natural gas storage levels reflect this chill: overall US storage levels are now below 2 tcftrillion cubic feet (gas), and the year-over-year deficit is 440 bcfbillion cubic feet (gas).

As a result, gas jumped back up to over $4/mcfcompanies usually convert gas production into oil, and taken the chart of many natural gas producers with it. The futures strip shows the market anticipates gas prices above $4.00 from July forward.

Can it last? The pros I talk to in Calgary dismiss this bump, saying shoulder season is coming in April/May and the North American gas price, along with all the good looking Canadian stock charts it has created, will droop then.

The Canadian arm of brokerage firm Raymond James has a slightly more bullish interpretation.

“For the last 3 weeks, we’ve seen some of the largest withdrawals from US gas storage in the last 10 years.

Yesterday’s withdrawal was 145 bcfbillion cubic feet (gas) (billion cubic feet) – the 5-year average was 89 bcfbillion cubic feet (gas) and the previous record was 115 bcfbillion cubic feet (gas) in 2007.

Last week’s withdrawal was 146 bcfbillion cubic feet (gas) – the 5-yr. average was 104 bcfbillion cubic feet (gas) – 146 bcfbillion cubic feet (gas) is the highest since 2003.

Week before was 171 bcfbillion cubic feet (gas) – 5-yr. average was 117 bcfbillion cubic feet (gas).

You get the idea…

And it is more than just cold weather doing this. Focusing on the last 4 weeks, 2008, 2007, and 2010 were all colder than 2013 – yet 2013 is seeing bigger withdrawals.”

(I love such simple, clear writing!)

They see the gas price that balances the market for the rest of 2013 being in the $3.85-4.15 range. I think if the market really had a comfort level that price could hold, the rally in stocks could continue (even though almost no one is making full cycle profits at that price).

Certainly gas drilling has fallen off dramatically (the US rig count is now 431 rigs, down 232 rigs from last year!) – yet North American production stays constant to slightly rising. The giant Marcellus Shale in the northeast US is THE perfect example… it just took over from the Haynesville Shale in Louisiana as the largest producer of natural gas in North America at over 7 bcfbillion cubic feet (gas)/d-while the rig count in the play dropped by a third. A third!

Another brokerage firm, Canada’s National Bank Financial, points out that in the US, “Residential/Commercial demand has been up about 17 Bcfbillion cubic feet (gas)/d (+50%) over the same period last year, with cold weather expected to persist through the week ahead to provide near-term support.”

Denver-based Bentek, one of the best natural gas forecasters, is projecting storage levels exiting the winter season (end of March) at 1.7 Tcftrillion cubic feet (gas), which is 25% below the same period last year and in line with the five-year average.

Canada’s FirstEnergy says anything below 2 Tcftrillion cubic feet (gas) at the end of March is a good sign.

Canada continues to have lower production than last year – a 6-year trend now.

But of course, US residential demand will drop as the warmer spring shoulder season arrives – in my mind, that continues to leave US power generation demand as the swing vote. Natural gas pricing, and most of Canadian junior/intermediate stock charts, will live or die on that one metric. Period.

THE OTHER BIG TREND: oil-weighted yield plays in Canada have made a fast and hard 15% jump since 3rd week of February. Enerplus (ERF-TSX), Petrobakken (PBN-TSX), Pennwest (PWT-TSX) and Penngrowth (PGF-TSX) are included here. These companies do have some gas, so that could be the reason.

But light oilAn oil of low specific gravity or relatively low boiling point (as below about 200° C) differentials in Canada – the discount Canadian light oilAn oil of low specific gravity or relatively low boiling point (as below about 200° C) is to WTI – is now at a very low $3-$5 (synthetic oil, produced by the majors, is actually a $5 premium to WTI now). This is a great price for Canadian producers.

But all these companies have stretched balance sheets (lots of debt… i.e. dividends sustainable?) and could just be having a dead cat bounce off their lows for being oversold.

Most, if not all, are still paying out more in capexCapital expenditures; drilling mone (capital expenditures, the industry lingo for drilling costs, etc) and dividends than the cash flow they’re taking in. As the market has moved away from rewarding growth to wanting more sustainability – where companies grow within their cash flow and not dilute by issuing more shares to fund their cash flow gap – it doesn’t make sense for these companies to run up in share price.

This current jump could be due to the rise in gas price – their jump co-incided with the larger than average storage withdrawals. It could be the chase for yield; the yield bubble. My suspicion is gas price is the main reason, with yield second.

As the shoulder season for gas approaches, the market will find out the truth soon enough.

by +Keith Schaefer

Last week I described how tax pools are a near-unknown—but increasingly critical—metric for junior oil and gas investors.

Tax pools shelter cash flow. E&Ps need them in order to retain cash for expansion—or to keep the coffers fat for paying dividends to investors, the way more and more companies are planning.

In the new, dividend-focused E&P sector, tax pools will determine success or failure for many firms.

Another important side to this story is that tax pools will increasingly drive M&A activity. Companies with shrinking tax credits will be looking for acquisition targets with deep tax pools.

Who might get bought and for how much? Let’s take a look.

Attractive Losses

We looked last time at two charts to understand tax pool dynamics across the Canadian E&P sector.

The first shows tax pools plotted against cash flow for a universe of E&Ps. The further right a company plots, the larger its pools.

The second chart shows the “cover ratio.” A measure of how many years of cash flow a company’s current tax pools can shelter. A bigger ratio means a longer time without having to pay tax.

A company like Southern Pacific (TSX:STP) has a high ratio of 27.5. But that’s partly because it has low cash flow—$26.4 million annualized.

If a company like this can’t ramp up its output and cash flow, it’s left with large tax pools that will never be used.

Those pools could, however, become an asset for somebody else… like a company with good cash flows running low on its own tax pools.

Let’s do the math. If ARC Resources (TSX:ARX)—for example—acquired Southern Pacific, the company would pay around $660 million, at STP’s current market valuation plus debt.

ARC would get all of STP’s assets, plus $725 million in tax pools. Pools not currently being used to shield asset income to any great degree. Pools that could then be applied against ARC’s cash flow from its other assets.

STP’s tax pools would cover about three quarters worth of ARC’s annualized cash flow. Assuming a 22.5% tax rate, that equates to tax savings of $163 million.

Subtract that cash in ARC’s pocket from the purchase price for STP, and the effective payout for the acquisition is only $560 million. The acquirer has picked up those assets at a significant discount to market.

Banking Assets

Sure, there are hitches. Using up STP’s tax pools would leave cash flow from the acquired assets unprotected if and when they see increased production.

But ARC could equally choose to simply “bank” those assets. Collecting a majority interest in 402 sections of oil sands leases. It’s possible that an asset like this could be shelved for future consideration, and still be accretive to overall net asset value.

The acquirer could even turn around and re-sell the assets. As long as the sale price was more than 77.5% of the original purchase price, ARC makes a profit on the transaction.

This “tax-driven” M&A could particularly target companies with technology-intensive operations like oil sands—operations where big up-front costs generate large tax pools without initial commensurate cash flow.

Athabasca Oil (TSX:ATH) is another example. The company holds $1.7 billion in tax pools, but is not yet making positive cash flow.

If valuations for such companies continue to fall (STP is down nearly 50% over the last year), it may hasten acquirers to look at these firms as tax targets.

The Right Combination

Companies targeting acquisitions may also look at the potential for assets to generate new tax pools.

As we’ve discussed, there are different types of tax pools… some more high-octane than others in terms of shielding income.

The two major types are Canadian Exploration Expenses—generated by drilling on new, unproven targets—and Canadian Development Expenses, created by drilling on mature, established fields.

Exploration Expense credits provide bigger savings. They can be written off 100% against cash flow in the year they’re incurred.

Only 30% of development expenses can be used in the year of drilling. Companies have to carry over the remaining credits to future years, waiting for the tax savings.

Companies considering M&A will be looking at how acquired assets can generate tax pools… particularly high-value Exploration Expenses.

Firms like Twin Butte Energy (TSX:TBE) and Zargon Oil and Gas (TSX:ZAR) make good acquisition targets this way.

These companies hold large acreage positions in proven oil plays in central Alberta and Saskatchewan. They have a lot of land, and lots of spots to drill exploration wells looking for new pools. At relatively lower risk, given their experience in these fairways.

Such projects could work well for companies like ARC and Peyto (TSX:PEY). Companies that need additional tax pools.

By acquiring a Twin Butte or a Zargon, the larger firms get acreage where they could launch exploration drill campaigns. At a size that generates meaningful tax pools. But with an acceptable risk-reward profile.

This is a win-win. Smaller companies with large exploration grounds are going to be hard-pressed to fully explore these projects. They can’t afford to commit a lot of dollars for exploration in the current, tightening financial climate.

But bigger firms with a balanced portfolio of development and exploration projects can spend exploration dollars. Squeezing more value from their exploration bucks by using the high-powered tax pools from exploration drilling to shelter income from their mature assets.

Investors should look for smaller companies with large acreage positions in proven plays. Such projects will become increasingly valuable places for E&Ps to scale out the drilling they need to create their future tax shelters.

- Dave Forest, guest editor

Part 1 here
Part 2 here

In Part 1 of my series on tax pools, I explained how the new dividend-paying junior producers will use up their tax shelters by drilling less—crimping cash flow much sooner than expected.

In this article, I create a “tax pool universe” to help investors discover:

1. which companies have big tax pools that will keep the taxman away
2. which ones are being pushed to the brink of taxability—where a big chunk of cash flow is suddenly vaporized
3. how you can find this information for yourself, making you a better investor

Below, I use the companies in the BMO Nesbitt Burns coverage universe that have reported their current tax pools (not everyone does), and then measure this against corporate cash flows (annualized for the 2012 calendar year).

On the horizontal axis is total tax pools for all E&Ps that have reported. On the vertical axis is their cash flows—annualized for those companies that have not yet reported their Q4 financials.

There are different kinds of tax pools. Some more valuable than others, because a greater portion can be written off against income immediately, rather than drawing out the deductions over several years.

For this analysis, I look at total tax pools—because many companies only report their total, without breaking it down into different types. This metric still gives a useful picture of who has enough credits to shelter income for the coming years, and who is going to get hit with a stiff tax bill soon.

(The closer to the bottom right in the chart—the better for preserving tax pools.)

A few things jump out from the analysis.

The oldest and largest companies have generated the largest tax pools (plotting further right on the chart)—because they’ve drilled a lot of wells over their lifetimes.

Enerplus (TSX:ERF) and ARC Resources (TSX:ARX) top the list for total tax pools, holding just under $3.5 billion and $2.5 billion in pools, respectively.

Peyto (TSX:PEY) also holds significant pools, at around $1.3 billion.

Smaller firms range between about $50 million and $850 million in pools. Whitecap Resources (TSX:WCP) is at the top end of this range. Twoco Petroleums (TSXV:TWO) is at the lower end.

This is a big spread for tax pools across the space. Interestingly, these companies all have a much tighter range of cash flows, from about $25 million (Southern Pacific—TSX:STP) to $130 million (Twin Butte—TSX:TBE).

That means some of these smaller companies have very large tax pools relative to cash flow—enough to shelter income for several years. Whitecap is a good example. But we see that others are running on tax-pool fumes, such as Raging River (TSXV:RRX).

One anomaly on the chart is Athabasca Oil (TSX:ATH). The company has large tax pools of just under $1.7 billion. That’s because of large amounts of cash spent on setting up its capital-intensive oil sands operations.

But the long development horizon on these projects means Athabasca isn’t yet making any money—making the company a tax pool bank that just keeps accumulating credits.

The Cover Ratio

Another way of looking at our universe is the “cover ratio.”

That’s a company’s total tax pools divided by yearly cash flow. In other words—how many years tax credits can shield income at current production rates and netbacks.

Companies with a high ratio like Southern Pacific, Anderson (T:AXL), Arcan (TSXV:ARN) and Whitecap (TSX:WCP) have the most “covered” cash flows. (Twoco Petroleums is excluded from the chart. The company has an extremely high ratio by virtue of its very low annualized cash flow of just under $400,000—part of the reason the company just received a $19.55 million demand note from its lenders.)

Those with low cover ratios can only shield their cash flows for a short time before taxes kick in. For Raging River the ratio is only 1.8. ARC Resources is also at the low end, at 2.5. Despite that company’s large tax pools, it cash flows nearly a billion dollars annualized.

This metric is revealing. Consider ARC and Enerplus—two companies widely regarded as comparable “elder statesmen” of the Canadian oil patch.

Both produce considerable cash flows and dividends for investors. But Enerplus enjoys double the cover ratio of ARC, at 5.1.

The analysis also shows that companies like Bonterra (TSX:BNE), BlackPearl (TSX:PXX) and Angle Energy (TSX:NGLNatural Gas Liquids. Components of natural gas that are liquid at surface in field facilities or in gas-processing plants.) enjoy very comfortable cover ratios. Investors buying these firms should be free from a sudden visit by the taxman.

Be Tax Aware

Unfortunately, tax pool information is not required in standard TSX company financial statements or MD&As. Investors may find numbers from select companies in such documents (search “tax pools” in your PDF search function for a quick look), or in Annual Information Forms (available on SEDAR).

For companies that don’t report numbers in any of these, a phone call is necessary. Ask management about their total tax pool holdings. Better still if they can break that amount down into Canadian Exploration Expenses (which can be used 100% in a given year) and Canadian Development Expenses (where only 30% can be used each year).

In the new “growth and dividend” E&P world, these things are critical to note for investors. Stock-buyers may find companies with unrecognized tax-pool value. Look for those firms that have high cover ratios—big tax pools relative to their cash flows.

Equally, beware (or at least be aware) of companies with small and shrinking tax pools. These companies will “gear down” in cash flow when they start paying taxes. Lower spending = lower production = lower valuation.

For such firms, the question is, “Would I buy this stock if its cash flow suddenly dropped 20%?”

If the answer is no—and the tax pools are tight—stay away.

- Dave Forest, Guest Editor

Publisher Note: In Dave’s next–and final–story (part 3), he’ll show you how this little-known but all important tax pool metric could start driving M&A activity in the oilpatch–and who the most likely targets are.

Read Part 1 here.

One question investors should be asking about new dividend-focused E&P companies in the Canadian oil patch is:

How will they pay their taxes?

Deferring income tax payments is a major part of the business strategy for most junior E&Ps—one that investors don’t realize. Investors have become so used to junior producers (almost) never paying taxes, it’s hard to imagine how paying taxes could affect valuations (read: stock prices).

Oil and gas companies typically build up “tax pools”—credits that can be claimed against income—as a result of their capital spending programs, on drilling wells and building facilities.

But income-focused E&Ps are today slowing their capital spending programs, choosing to divert more cash flow into dividends and less into drilling. Whitecap Resources (TSXV:WCP) for example, announced it will reduce capital spending to approximately 63% of cash flow.

Lower capital spending means these companies generate fewer tax pools. Companies pay more tax, sooner—reducing cash flow. Valuations—as a multiple of cash flow, and net present value of in-ground oil and gas reserves—then decline, meaning lower share prices.

A hypothetical example goes like this: ABC Oil cash-flows $100 million per year—entirely tax-sheltered by its tax pools. It trades at a five-times multiple valuation of $500 million. The company has 100 million shares out, so enjoys a $5 stock price.

But now drilling slows, and tax pools are used up. ABC’s $100 million cash flow now becomes taxable—$25 million is lost to the government (Alberta’s all-in corporate tax is about 25%). Earnings drop to $75 million yearly, and the valuation slides to $375 million. The share price falls to $3.75.

This is potentially a big deal, especially for smaller companies: many E&Ps have avoided paying taxes completely over the last several years because of their spending-driven tax credits.

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Whitecap stated in its last annual information form that management did not expect the company to be taxable until 2015. Renegade Petroleum (TSXV:RPL)—also an announced converter to the income model—estimated it wouldn’t become taxable until late 2013 or early 2014.

Deferring taxes helps these companies in a few ways. First and foremost it boosts their available cash flow, giving them greater scope for exploration work, and property or corporate acquisitions.

Deferred taxes also affect the net present value for an E&P’s in-ground oil and gas reserves as reported every year. Companies show values for their un-pumped petroleum in two ways: the before-tax value and the after-tax value.

Deducting cash flow for taxes reduces the after-tax NPVNet Present Value (the number most analysts look at)—all the more so on a percentage basis, when taxes kick in during nearer years that carry higher, less-discounted values.

Some analysts even believe that small E&Ps are unviable after they become taxable—as a start-up you need that extra ooomph in cash flow in order to establish company-building fields.

The drive to stay sheltered from taxes even led to a movement (largely done with now) to re-structure failed technology companies into junior E&Ps in order to take advantage of huge, transferable R&D tax credits racked up by these companies. Trafalgar Energy, which later became Midway Energy—acquired last year by Whitecap—was one such restructured “tax-loss” company.

Exploration Versus Development

Tax credits applicable to E&Ps come in several forms. The most important are:

• Canadian Exploration Expenses—costs associated with drilling and completing wells on unproven exploration targets (100% deductible annually)

• Canadian Development Expenses—expenses on infill or enhancement drilling at established fields (30% deductible annually)

• Undepreciated capital costs—deductible at around 25% annually for most companies

• Canadian oil and gas property expenses—deductible at 10% annually

Drilling represents the major portion of capital expenditures for most junior E&Ps, who tend to spend less money on pipelines and major facilities. Start-up companies usually generate drilling-related annual tax pools quickly in the beginning, as they drill exploration wells that carry 100% annual write-offs.

Once companies make discoveries, they drill fewer exploration holes. Drilling now focuses on development wells that carry only 30% write-offs. This usually leads to slower generation of tax pools—although development drilling tax credits are still significant because development programs are carried out on a larger scale. Meaning higher overall costs, compared to exploration drilling.

During this critical shift from exploration to development, changes in capital spending greatly affect tax pools.

Compare Renegade Petroleum—which announced a switch to the dividend model early in 2012—with Whitecap Resources, which remained in spend-and-grow mode during most of the year.

In 2011, both companies were in growth mode. Renegade’s Canadian development tax pools grew by 109%, with Whitecap’s increasing by an even-larger 185%.

But in 2012 (up to last financials in Q3), Renegade’s shifting strategy saw its development tax pool growth slowed to 41%. A natural consequence of the income-and-growth model, because the company claimed some of its existing tax pools against cash flow. But Whitecap’s tax pool growth continued apace, up 186%.

Whitecap will now cut spending as it switches to the income model. Drilling will slow, and so will tax pool growth. Like Renegade, WCP will have fewer tax credits to claim.

The Taxman Cometh

The question is: how soon will these companies have to start paying tax?

As of the end of Q3 2012, Whitecap held up to $195 million in tax pools available for the current year. The company cash-flowed approximately $130 million through the first three quarters of 2012—meaning its annualized funds from operations should come in lower than its available tax pools, sheltering all this money.

Renegade is in a similar boat, with up to $59 million in tax pools available for use this year (as of the end of Q3 2012), against cash flow so far in 2012 of just over $44 million. They too should come in un-taxable.

But there’s not a lot of room to breathe. When companies spend less, they generate tax pools slower. They become taxable sooner.

That’s exactly what’s happening. Renegade announced mid-January that its capital spending for 2013 will drop to just under $80 million—27% less than the $110 million RPL spent in the first nine months of 2012. Both companies look like they could come up against taxability in 2013 or 2014.

For Renegade that’s in line with management announcements. For Whitecap, it would be sooner than the company forecast last year (management will put out updated estimates in the next few months).

Earlier tax would obviously pinch cash flow… meaning a lower stock price and after-tax value of reserves.

Tax-Driven Consolidation and M&A

Investors need to look for management teams that recognize the tax issue. Ones prepared to deal with it. “We discuss it for sure,” says Renegade Controller Mark Lobello.

What can companies do? One solution could be increased M&A. Acquiring not only production and reserves, but also tax pools from companies that have spent large amounts on drilling.

Whitecap, for example, gained tax pools when it acquired Midway Energy in the second quarter of 2012. During that quarter—largely as a result of the acquisition—Whitecap’s tax pools grew by $318 million… including over $143 million in critical Canadian Development Expenses.

This adds as much as $75 million in pools applicable this year—helping to shelter about 50% of WCP’s cash flow.

Renegade also looks at M&A with tax pool-rich companies as an answer, according to Lobello. “We’re always looking at tax-loss acquisitions,” he notes.

E&Ps staring down taxability may look to acquire or merge with firms holding significant tax pools. Ironically, the preferred targets would be companies that have under-performed:  those that drilled a lot, but failed to cash flow enough to eat up tax pools. Such companies often trade at reduced multiples, making them even more attractive as targets.

Whitecap’s acquisition of Midway is a good example. Without Midway’s tax pools, WCP would have been close to taxable in 2012. That would have meant a sudden, unexpected fall in cash flow—the kind that causes analysts and investors to lower target prices and sell off a stock.

Such negative revisions will be reality in the new income-focused E&P sector. Investors need to check tax pools against cash flow—to see who is safe and who is in danger of an unexpected tax-driven bite out of profits.

- Dave Forest

Read Part 2 here and Part 3 here.

Natural gas bulls keep pointing to the declining gas rig count in the US as a reason for a near-term turnaround to the upside in prices.

The gas rig count in the US has dropped by more than half in the last 18 months, but production continues at record levels—around 63-64 billion cubic feet per day (bcfbillion cubic feet (gas)/d). Why is that?

First, the stats: The February 15 Baker Hughes rig count—the Bible of the industry—showed the gas rig count at 421, the fifth-lowest in the current run down—that’s down from 1,600 in 2008, or almost a 75% drop. Just this last year the gas rig count has dropped 41%.

(You can find this chart each week at http://intelligencepress.com/features/bakerhughes).

There are two obvious reasons for this—one is that there is more “associated gas” with oil production, especially in Texas (not so much in North Dakota on a per well basis, but overall the Bakken is up around 1 bcfbillion cubic feet (gas)/d in gas now).

But the big reason is drilling efficiency. When I go to conferences, I tell the crowd—fracking isn’t improving every year. It’s not improving every quarter. It’s improving every month. That shows up in the reduced time it takes to drill a well now, thanks to improvements in horizontal drilling techniques, and in the amount of gas each well is able get out of the formation—thanks to improvements in hydraulic fracturing.

The problem is, few companies want to brag about how much they’re improving production, so hard statistics are hard to come by.

In one of his blog posts last year, industry expert Rusty Braziel of RBN Energy published some statistics from Southwestern Energy, which provided in-depth numbers on its drilling operations in the Fayetteville shale in Arkansas and Oklahoma.

Over the course of five years, the company’s average drilling time per well plunged from 17 days in 2007 to only 8 days in 2011, falling by more than half. In just one year from 2010 to 2011, drilling time dropped more than 27 percent. Over the same five-year period, the later length of wells grew by 82 percent, and initial production more than doubled, rising from 1.65 million cubic feet per day in 2007 to 3.3 million cubic feet per day in 2011.

All the while, the cost per well hovered around the same level, dipping 4 percent from 2007 levels.

So for the same costs, drilling rigs were producing more than twice as many wells, with more than double the initial production. That means the initial production additions per rig grew by 338 percent in half a decade. If the rest of the energy industry saw the same kinds of improvement over the same period, even while cutting rig counts by three-quarters from their 2008 peak, we would expect to see a modest rise in production from simple efficiency.

These changes are not just coming over the course of years, either. Southwestern reported huge swings in IP rates even from quarter to quarter. Between the first and second quarters of 2009, average IP rates at the company’s wells rose 20.7 percent, and eight quarters out of five years saw an increase of at least 13.4 percent.

And other companies have seen comparable improvements. As recently as the third quarter of 2012, exploration giant Anadarko reported a 14 percent year-over-year reduction in drilling costs, along with a 40 percent drop in completion time at its Marcellus operations.

Future of Oil and Gas Goes Through Efficiency

Others are not only pointing out drilling efficiencies, but say they will continue into the future. A report released last summer from Credit Suisse hinged its estimates of future American oil production on expected improvements in efficiency.

Credit Suisse estimates that that drilling and completion times will fall by around 40 percent within the next decade as exploration companies become more familiar with new technology and new geology. Some of the newest emerging plays, particularly in California, would come closer to a 50 percent reduction.

That amounts to a less dramatic improvement than that observed by Southwestern over the past five years, but it would still allow energy firms to increase well counts by 27 percent by 2016 with only an 11 percent rise in rig counts.

The report also assumes steadily improving initial production, a trend that has already been observed in shale developments in North Dakota. Credit Suisse sees IP rates rising 21 percent over the numbers seen at the end of 2011.

As positive as these numbers sound, Reuters reports that consulting firm Bernstein Research points out the obvious other side of the coin—efficiency is improving dramatically because fracking operations at present are highly inefficient.

The firm released research last year suggesting that as many as half of all fracking stages contribute no additional production from a given well. In turn, the vast majority of all production – 80 percent – comes from only 20 percent of all fracking stages; yet another example of the somewhat infamous Pareto principle, commonly known as the 80/20 rule.

Nansen Saleri, president and CEO of consulting firm Quantum Reservoir Impact, told the news source: “In a few years the techniques used today for fracking will be viewed as primitive.”

So as investors watch the gas rig count with a perplexed face, the industry has been steadily reducing the cost of drilling, lowering the break-even price of natural gas—and disappointing the bulls.

by +Keith Schaefer

When investors ask me about investing in natural gas stocks, I give them the single most important question to ask producers: How much condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) do they produce? Ask about condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil).

CondensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) is essentially a very light oilAn oil of low specific gravity or relatively low boiling point (as below about 200° C) which is condensed from rich natural gas and solution gas from oil. And the price of it is skyrocketing, because it’s used to dilute both regular heavy and synthetic oil from the oilsands. It’s the saving grace for a lot of Canadian producers.

See this chart below. It shows Canadian condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) prices against WTI—see how the value of condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) is rising rapidly? In August 2012 it was only $3/barrel more than WTI. Now it’s $14 more—giving producers with lots of condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) even better economics than most oil producers!

And prices will only get better for condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) producers, one Alberta based oil and gas marketer told me, asking to remain anonymous.

“Supply and demand (for condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil)) are just touching each other. Any more heavy oil coming onto market will have a big impact. We need to find other sources (of condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil)).”

Or, he says, condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) prices could go even higher. He estimated that if the oilsands increases production by some 400,000 barrels per day (bopd) a year for the next several years, an extra 100,000 bopd of condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) is needed—each and every year.

I’ll explain in my next story, condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) part III, how US imports of condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) are happening, but not fast enough.

In Canada, most condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) is found in shale and tight gas formations. In the US, it’s mostly in gas associated with shale oil, especially the fast-rising Eagle Ford play.

In the United States, all this condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) is almost a problem. US refiners spent billions of dollars over the last decade to process more heavy oil. As a result they can’t really handle this light stuff.

But for Canadian gas producers, condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) is the only product that gives them substantial positive cash flow (a very few producers do make some cash flow on dry gas.) That’s why it’s so important to know how much condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) the gas producers are flowing.

Canada’s Thirst for CondensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil)

In the oil sands, condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) is used as a diluent to ‘thin down’ bitumenVery viscous (gooey) form of crude oil – a thick, sludgy substance – so it will flow through pipelines. Since bitumenVery viscous (gooey) form of crude oil production is climbing steadily, condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) demand is on the rise. Supply is struggling to keep up.

Canada now uses some 275,000 barrels of condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) per day as diluent. Canadian producers churn out 165,000 barrels per day (bpd), meaning oil sands operators already rely on imports to fill a 110,000-bpd gap.

That’s good, but it will probably get even better. Capital spending in the oil sands is expected to exceed $20 billion per year for the next five years. The more bitumenVery viscous (gooey) form of crude oil that is pulled from the sands, the more diluent Alberta will need to move all that heavy oil to market.

This year Canadian demand for condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) is expected to average 300,000 bpd. By 2020 demand is expected to reach 670,000 bpd, according to the Canadian Energy Research Institute, which also provided the following chart.

As you can see from the bottom red part of the chart, Canadian condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) production is not expected to increase much in the coming years. That in itself is bullish. But there are two other infrastructure bottleneck that should help keep condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) prices high for at least two more years.

One issue is that Canadian NGLNatural Gas Liquids. Components of natural gas that are liquid at surface in field facilities or in gas-processing plants. processing facilities are basically full. That is impacting (reducing) condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) production in the short term—creating further supply stress.

So Canadian producers are shipping in tanks directly to their wellsites, and trucking it to local markets; they’re not sending via pipe to processing plants (fractionation plants). The other reality is—and I’ve said this many times—the energy game is changing so fast in North America—fast rising production in both oil and gas, new channels to market (rail)—that nobody knows what the landscape is going to look like 2-4 years from now.

That uncertainty is causing Big Energy Money to be cautious about increasing refining capacity for oil and gas in Canada—which again, is good for commodity prices.

The second bottleneck is pipeline capacity INTO Canada.

The US is actually swimming in condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil)–it accounts for as much as half of the output from US shale oil and gas basins. Refiners are buying some of it simply because it is cheap, but a condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) glut is also developing in the Lower 48.

Now however, there is only Enbridge’s Southern Lights pipeline bringing condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) into Canada, and it’s not near enough. (There is some incoming condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) by rail, but now that is still small.) In Part II of this series, I’ll explain in detail this bottleneck, and what’s happening to get rid of it.

Once that glut starts moving into Canada apace, the price premium that Canadian condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) producers are currently enjoying will shrink. CondensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) will still carry a good price, but the edge will be smaller.

But I expect that to be at least two years away, and if oilsands production keeps increasing, it may be even longer.
In conclusion—the growing demand for condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) in the oil sands is driving up its price. This isn’t just saving the lucky Canadian gas producers who have high condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) levels, it’s giving them better economics than most oil producers.

Pipeline bottlenecks in the US and processing plant issues in Canada should conspire to keep condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) prices high—making it the best (and least volatile) upstream commodity stories in North America.

Next, I’ll explain in detail what’s happening to condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) in the US, and the efforts to get as much up to Canada as fast as possible. In general, ‘fast’ means 2014 at the earliest, giving investors lots of time to benefit from strong domestic condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) prices.

by +Keith Schaefer

Read Part 1 of my condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) series here. 

P.S. I think right now is one of the BEST times for investors to discover my #1 condensateAlso known as C5Also known as condensate (gets the same price as oil) (gets the same price as oil) play in Canada. Learn all about my Top Pick risk-free right HERE.