What Is the Break-Even Price for Natural Gas Producers?

There is a lot of confusion amongst investors - both retail and sophisticated institutional investors - about what the average break-even price is for natural gas producers in North America.

I interviewed a couple Calgary junior gas company management teams to understand this better.

I’ll try to simplify their industry lingo, and explain what some of the typical costs are for natural gas producers. After reading, I hope investors can:

• 1. understand the stages oil & gas go through from the wellhead to the end buyer
• 2. roughly what each of them costs in terms of per barrel of oil or mcf of gas
• 3. have an idea on what the breakeven price - of an average natural gas producer
• 4. hear who three low cost natural gas producers are

I’ve used a Canadian example but the system works much the same in the US.

After company ABC drills a successful gas well producing 1 million cubic feet per day (1 mmcf/d). That’s a thousand thousands, and the price for one thousand cubic feet (mcf) that day at the Edmonton gas terminal, AECO, is CAD$3.40.

The actual price the company receives is reduced by the distance they are from the AECO hub - the transportation discount. The quality of the gas also influences the price - higher heating content (i.e. more liquids in the gas) means they receive a higher price.

The gas from that well needs to get, at the end of the day, to the natural gas pipeline grid, which in Alberta is the Nova pipeline system. So Company ABC must first build their own pipeline to connect their well to an intermediate-stage gathering system. That pipeline could be a few hundred meters or several kilometers, so that can be expensive. If ABC doesn’t own that gathering system, they must pay a fee to whoever owns it. Cost: $0.30 per mcf.

The gathering system is tied in to Nova at a meter station where Nova measures how much gas comes in to their system. Then it is transported on another pipeline (cost: $0.50 per mcf) to a plant to have the gas processed (to get the gas to pipeline spec - remove water, carbon dioxide, hydrogen sulfide etc. - cost: $0.90 per mcf) and to compress the gas to get it up to pipeline operating pressures.

Now the raw gas and its associated fuels have been refined so Company ABC can actually sell them to an end user.

But the actual buyer of the company’s gas is the “marketer” - the middle man. Gas marketers (such as Enron, SEM Canada, Plains, Tidal, Nexen Marketing, etc.) contract space on the Nova system and the large trunk lines (Alliance, TCPL, etc.) to get the gas to the end users (utilities, industrial users, etc.). Sometimes companies get to choose their gas marketer, but if their intermediate stage pipeline is owned by a marketer then they may be forced to use them.

Marketers get a reputation for getting the best gas price they can for Company ABC on a given day. Pricing varies, but it is based on AECO spot prices (see ngx.com). Each basin has its own spot prices, based on NYMEX with adjustments for transportation cost (to get the gas to New York) and currency exchange (in the case of AECO).

There can also be large price swings in different basins if the supply is too large for the physical export capacity on the pipelines - “trapped gas” - or the inverse also. That’s one reason you see the natural gas prices so low in the major gas producing areas of the Midwestern and Rocky Mountain states of the USA. There is a lot of gas fighting for pipeline space. NYMEX spot prices currently are about US$3.60, which is about C$4.50 but current AECO spot prices are $3.40, showing a $1.10 differential - that difference is the transportation for the cost per mcf to get the gas from Edmonton to New York.

Ok, so transportation and processing costs are now 30 + 90 + 50 = $1.70 per mcf - half of the wellhead price. What other costs are there? Royalties of course. Give Caesar his due. In Alberta this 1 mmcf/d well has a royalty of $0.70 per mcf, so Company ABC now has $1/mcf left. Company ABC’s operating cost to maintain their own well would likely be $0.20 per mcf, leaving them with about $0.80 netback, or profit per mcf.

Administration - G&A - and interest on debt could be as low as $0.50/mcf for a good producer (but many are more like $0.70/mcf). We are now down to $0.30/mcf cash flow.

The visual math is $3.40-(30+90+50+20+70+... cash flow. And we’re not done yet.

We have not yet factored the cost of exploring for and drilling the well. The industry calls this Finding, Development and Acquisition, or FD&A. After reading dozens of comparative analysis spreadsheets from various brokerage firms, I can tell you that best-of-breed natural gas producers have $2/mcf FD&A.

According to Calgary brokerage firm Peters & Co., only Storm Exploration (STXPF.PK) had finding costs under $2/mcf last year in their 34 company coverage universe, with little Berens Energy* (BEN-TSXV) right at $2 and Trilogy Energy Trust (TETFF.PK) at $2.01/mcf. The median was $3.29/mcf. (The low cost producers of any commodity have the best leverage when prices start to rise back to break even).

If you back in $2/mcf finding costs to the $0.30 cash flow (on $3.40/mcf gas) we hypothetically shown above, it intimates a $4.95 breakeven price for the lowest cost producers. We really need to bump that up by 30 cents as well, because on a higher realized gas price the royalties would be higher. We are now at CAD$5.25/mcf breakeven price for natural gas producers.

(Most analysts would argue that FD&A is the wrong number to use in calculating costs - the better number is a line item on the balance sheet that reads “Depletion, Depreciation and Accretion”. This is the cost to book proven reserves, and is a tougher test of costs. Only a handful of companies would have DD&A costs under $4/mcf - making the breakeven price CAD$7.25/mcf.)

This is a very simplistic version of a natural gas company’s cost structure, with conventional vertical wells. And it uses an example of an average sized well in the Western Canadian Sedimentary Basin; it is NOT an example of one of the big wells (10 mmcf/d ++) that comes from horizontal drilling.

Southwestern Energy (SWN) in the US, a major gas producer, says that their large horizontal wells at their US shale operations do break even at US$3.60 gas - finding costs of $1.60 and operating costs of $2/mcf. They added that at current prices, drilling might be declining a bit but they see nobody shutting in production in the big US shale plays. Depending on the hub, natural gas is in the $3.20 range at NYMEX and under $3 in some interior hubs.

This illustrates that nobody is making money at these price levels. I paraphrase one quote I read on the web recently: At these low prices, it’s not a wonder that drilling for natural gas is down, it’s a wonder anybody is drilling at all.

Disclosure: I own 15,000 shares of Berens Energy, BEN:TSX

Comments

[Eric Fox:]

Excellent article. Question - would you consider the F & D cost a "sunk cost" at this point when the company makes a decision on whether to produce from existing wells? For new drilling I assume they would include this figure in return calculations.

May 01 11:29 AM

[Mad Hedge F...:]

$3.50

May 01 12:54 PM

[Mistrofan:]

$3.315

May 01 01:35 PM

[Ferdinand E...:]

Very good. Very informative. Of course, when things get back to normal, a price of 7 dollars will not be around for long, although I won't bother explaining why.

May 02 10:23 AM

[whisperonth...:]

For those of us who are still reading everything we can to learn as much as we can, I have to say that was a really stupid comment, Mr. Banks. I have learned that those who "won't bother explaining" usually can't explain. The only way to prove otherwise, of course, is to explain. Thanks for showing us where you stand.

Of course your responsibility is not to educate the rest of us, I know that. And it is your right to keep your information to yourself. This equates to a child saying, "I know something you don't know. Nyah nyah nyah!" Children may think that's cool, but adults know it's childish. If you don't wish to share your knowledge, keep it to yourself.

May 02 11:16 AM

[toobad41:]

From those I've talked to in the Barnett Shale they still get more than $6 ( hedged). The hedged price will eventually expire and wells will be shut-in until prices improve. At $6 they get a 25% rate of return (after tax).

May 02 01:19 PM

[Old Trader:]

I would guess it would depend on how long until the hedges expire, and what happens to prices in the interim.

Btw, I thought this was a great article, in terms of educational value. The author is correct in saying there are a lot of numbers being bandied about about costs, and its certainly true in almost every industry, there are the low(est) cost producers, but it was useful, imo, to see the costs broken out, along with explanations.


On May 02 01:19 PM toobad41 wrote:

> From those I've talked to in the Barnett Shale they still get more
> than $6 ( hedged). The hedged price will eventually expire and wells
> will be shut-in until prices improve. At $6 they get a 25% rate of
> return (after tax).

May 02 05:08 PM

[woolyboogur:]

Very good paper on gas costs in Alberta. My take is that it's a nominal US$5.00 making Alta gas non-competitive in US markets and may result in shut-in wells in Alberta. Now if the best US producers break-even is $3.00 we're probably going to see more marginal US wells shut in. If these estimates are in the ballpark and US consumption continues we should see sales price increase which will result in shut in well back on line. Then prices will drop and this cycle will continue to repeat with conitually vacillating in the short term. In the longer term we should see prices rising because of reduced drilling. The longer term window will show further prices increase as Obama's carbon initiatives favor gas over coal in electric power generation and transportation conversions.
Hank

May 02 06:59 PM

[Delojozafado:]

Shoulda woulda couldas... Forget about it!!! Gas is heading for $2.25/MM~BTU! that is when ideas like Storm will start working. Storm is a great idea just because of the ultimate currency advantage. But then so were SNG and Challenger. Be careful out there. In the medium term the only people who are going to make money in Nat Gas are going to be the owners of gas themes with distributions. The same kind of negative feedback cycle effect that is effecting the over all economy is at work in the North American gas market. Oil keeps testing in the mid $40's/BBL range and that kills off Canadian oil sands oil mining and manufacturing which is nat gas intensive. That glut of gas not consumed is then sold to the lower 48 which is being flooded (pun intended) with spot cargoes of foreign sourced LNG from the global LNG market that has a huge glut of it's own due to the global economic slowdown. These spot cargoes come here to collect on the still relatively strong US dollar. Gas is prices are then pressured which in turn pressures oil. Oil is pressured down and .... The place money will be made in the shorter term is in these electric utilities that are going into ramp up for the Summer A/C cooling season. Just about all of them have gotten big rate increases over the last 18 months from PUCs in reaction to their spiraling costs for fuel. Big rate increases and now suddenly lower ACTUAL costs for fuel, sustainable for the Medium term means these guys are going to be money machines. Their most recent quarters have been disasters against the loss of sales to the commercial market and hedged fuel contracts. That is exactly now an expiring situation. Buy the CEFs like ERH and DUC and take those yields and put them in your pocket. Let them run up another 15 -20% and then put 8% stops under them. Same idea buy the great yields on FPL-C or F, ED-A, & XCJ or for a small bit more risk AES-C, ATPWF & EDE-D. Best watermelons come from Arkansas and EDE is what keeps it cool with their own gas utility segment and peaking G turbine generators on those really hot sticky days and nights that the watermelons so love. When gas has PROVEN it's bottom and that must depend on the US dollar finally morphing into a US Pe$o, gradually switch into the CHK-D, ENY, STO, BRGXF,BRGYY, STXPF & BIRDF. With the AES-C, ATPWF,STO, ENY, BIRDF and STXPF you get the exposure to the Nat gas on both price weakness to start and then strength developing in pricing longer term while enjoying exposure to "hard" currencies like the Loonie, NOK Kroner, as well as strengthening emerging market currencies (BG Group & AES) as well. All whilst receiving generous distributions while you await the cycle of gas finally bottoming and then reverting to the mean playing out. BY then the (TBT) will have hit +$60 and it will only be for the details left to be worked out on the new global reserve currency backed by some commodities basket. The CHIAMERO? perhaps. China will have a SPR three times the size of our own and have more than half the total weight of the world's above ground copper supply stacked up over thousands of acres.

May 03 12:19 PM

[Delojozafado:]

Another thought on this theme is of course the toll taking MLPs. Steer clear of the individual producing MLPS. Get a great MLP like EPD or KinderMorgan and then supplement with some ETFs &/or CEFs that will then contain either some indexed or managed positions in producing MLPs. The latter group (funds) completely resolves the K-1 forms and converts those issues to 1099 DIV& INT. The ones that have really been humming as of late are the INTEREST ! NOT dividend paying BSR, the MTP, and the KYE. Many of these have some very hefty premiums to NAV. As a KYN for example. Be careful not to over pay. Modest premiums though not value plays can generally be accepted if the yield seems appropriate to other similar investments and given that you would expect to capture that premium at some point when you are the seller. Gas and oil prices do in fact bias the share prices of MLPs but essentially they get paid for the product flow not so much the product. Use the funds like an ENY to avoid a disaster like an AAV, or a BSR to avoid one like an EROC. E for "EAGLE". Something about "Mooseport". But more about the partners being flipped the bird!

May 03 12:42 PM

[Jeff Durbin:]

I agree with your point that the article confuses average costs with marginal costs. It makes a big difference.


On May 01 11:29 AM Eric Fox wrote:

> Excellent article. Question - would you consider the F & D cost
> a "sunk cost" at this point when the company makes a decision on
> whether to produce from existing wells? For new drilling I assume
> they would include this figure in return calculations.

Jun 14 11:10 PM