We are entering the shoulder season, when demand for natural gas and oil wanes just as winter wanes—although this year, winter was a non-event, being 10% warmer than usual. Gas fundamentals reflect that ugly truth: Storage volume is 33% above the five-year average; prices are down 20% since New Year's Day alone.

"Why give it away?" asks one E&P executive who has stopped drilling dry-gas wells.

The industry is doing what it should: changing where it drills, selling underperforming assets and jumping on any deal that has oil or liquids potential. Some companies have made a splash by announcing big cuts in dry-gas drilling and shutting in wells, while others have more quietly done so. The chief financial officer of one large public independent told me confidentially that the company will not drill a single dry-gas well this year.

Although everyone insists the Marcellus is the only gas play that's still economic at $3 gas, Talisman Energy says it will cut spending there from $1.2 billion last year to $600 million this year, and from 10 rigs last year to three now.

Others backing away from dry-gas drilling activity include Chesapeake Energy Corp., cutting 26 gas rigs; Noble Energy, deferring 40 Marcellus wells; Consol, suspending Huron drilling; Pioneer Natural Resources, reducing its dry-gas Eagle Ford drilling; and WPX Energy (formerly Williams E&P), cutting its Marcellus and Piceance drilling program to eight rigs from 18.

But the Jefferies E&P research team says in a recent note, "Cuts now are too late to stem 2012 production growth." Jefferies cited Energen, which said it will cut its 2012 capex in the gassy San Juan Basin by more than half. "Yet…it will still drill through mid-year…gas production is still expected to grow 0% to 9% year-over-year. Despite the reduction in activity, EQT, CNX, and NFG are expected to grow volumes 30%, 12%, and 33% this year, while WPX expects production to be flat."

It's quite a turn of events compared to the high-rolling days of the Barnett, Woodford, Fayetteville and Haynesville shales. But it illustrates why companies and investors should never put all their eggs in one basket.

A corollary is this: There are assets, and then there are better assets.

"You can always fix a balance sheet that has a little too much debt on it, but you can't fix bad assets as easily," declared Aubrey McClendon. Did he say this recently? Probably. But my notes indicate the Chesapeake chairman and CEO said this in March 2009 at the Howard Weil energy conference.

As you recall, that was a bad year. The world economy had tanked, capital was nearly impossible to access, and oil and gas prices weren't helping. The U.S. rig count plunged. Service companies were laying off employees. Plains E&P chairman and CEO Jim Flores said at the time, "Like everyone else, we have some closets to clean out." PXP was reducing debt by selling assets in the Piceance and Permian basins, yet buying in South Texas and the Haynes ville. That kind of asset rotation is still the answer.

Now we've come full circle some three years—and a ton of shale-gas production—later. You can relate to the fact that the worst assets are getting worse and the best ones are getting better.

Tudor, Pickering & Holt Securities says it still looks for $4 gas in 2013.

I asked the CEO of a private Houston E&P recently, what do traditional and smaller companies do if they are not in a shale play? How do they attract investor dollars, get acreage, and tie up a rig and frac crew? He replied that it is tough. After looking at several plays, he is getting into the Brown Dense now, because the acreage there is still affordable. In other resource plays, it is not. "I am not going to pay $1,000 an acre."

Then too, he was participating in other companies' wells as a way to be involved in a hot play, since he could not go it alone.

There is no sense spending money on the way down, so wait until service costs are really low. Prioritize all decisions based on rate of return. Even in the good old days, when natural gas commanded a much higher price, CEOs admitted the shale plays would not be cash-flow positive until 2012 or 2013—too many wells to drill first, to hold leases.

If a 6.5-Bcf Haynesville well made a 10% return at $3.30 gas, what now? That cash-flow positive event has been pushed out another year.

We look forward to seeing you and sharing what's new at the 3rd annual Marcellus Midstream Conference & Exhibition in Pittsburgh, March 19-21; and at the 7th annual DUG in Fort Worth on April 23-25. Both events continue to evolve just as the industry does. See you there.

For more commentary from Leslie Haines, see OilandGasInvestor.com.