An interior oil and natural gas supply glut, the result of strong output from shales and tight oil and gas plays, is developing because infrastructure can’t keep up, and that in turn is pressuring prices, according to Canaccord Genuity.

Domestic oil development is surging and contributing to already abundant U.S. natural gas supplies, with 15-20% of the output in an average oil well estimated to be gas, analysts John Gerdes, Cameron Horwitz and Ryan Oatman said in a note Wednesday. Since diverging from historic norms in the fall of 2009, the domestic oil rig count has more than tripled and now constitutes more than half of U.S. drilling versus 20% in 2007-2009, they noted.

“The production composition of an average oil well includes 15-20% natural gas, which seems reasonable given several recent oil plays have at least a 20% gas composition (i.e., Barnett Combo, Bone Spring/Avalon, Eagle Ford).”

Going into 2012 there appears to be no letup in sight. The energy industry is likely to continue to “markedly” outspend cash flow, assuming a $4.00/Mcf gas price and a near-10% reduction in U.S. gas-directed activity (800-850 gas rigs). Under that scenario, the industry is expected to be 30% free cash-flow negative.

“The imbalance seems reasonable to us given continued support provided by joint venture drilling and leasehold capture activity, primarily in the Marcellus Shale,” said Gerdes and his team. In 2013 the “financial disposition and historic behavior of the industry” suggest that exploration and production (E&P) companies may continue to outspend cash generation by 10%.

One reason for the increase in spending is North Dakota’s Williston Basin. The state is on track to leapfrog California as the third biggest oil-producing state after Alaska and Texas, officials said recently (see Shale Daily, Oct. 18). Canaccord’s research indicated how that may happen.

“With weather conditions supportive of a dramatic ramp-up in drilling and completion activity, we believe increasing operational momentum by Williston Basin operators will result in stronger than expected production growth over the balance of 2011,” said the analysts. “In the Bakken, the rig count has grown from an average of 177 in July to 200 as of the end of September.

“Following our review of North Dakota production data and after discussions with several Bakken participants, we are increasingly constructive on the 3Q2011 exit rates. With record drilling and completion levels in the Williston Basin and incremental hydraulic fracture capacity in place, we think North Dakota average quarterly volumes should grow 20%-plus sequentially to more than 450,000 b/d. In our view, this range is biased to the upside as we are consistently seeing operators generate increasingly better results west of the Nesson anticline.”

Coupled with the record level of North Dakota-Bakken directed drilling, Williston Basin E&P spending should continue to rise, they said.

Meanwhile, in the Permian Basin the rig count this month has jumped to 480 active rigs from 380 in late 2010, noted the analysts. “Since the beginning of 3Q2011 there have been more than 385 new horizontal drilling permits approved in the Permian Basin. In the Delaware Basin, the Bone Spring and Wolfcamp trends continue to dominate the permitting activity as these subplays continue to represent some of the most economic horizontal liquids plays at current strip prices.”

An uptick in permitting activity also was found in the southern Midland Basin of Texas, where recent horizontal Wolfcamp results “are improving. In our view, the most recent data points from the [Texas] university lands support our bullish thesis on the trend.”

And in South Texas in the prolific Eagle Ford Shale, “the rig count has grown from 110 in 4Q2010 to 230 as of October,” said the analysts. “Since the beginning of 3Q2011 there have been more than 900 new horizontal drilling permits approved for drilling in the Eagle Ford Shale. Much of the recent permitting activity has focused on the wet gas window in counties such as: DeWitt, Dimmit, Karnes, LaSalle, McMullen and Webb. We anticipate a continued trend of acceleration in the liquids-focused window given the relative productivity and economics these wells are demonstrating.”

Anecdotal evidence from operators with exposure in the wet gas window indicates “that rig activity will accelerate as the play transitions to a manufacturing phase. Accordingly, we believe the massive expansion of transportation and processing capacity over the next 18 months should thus generate meaningful production uplift for E&P businesses exposed to this portion of the Eagle Ford trend.”

Canaccord reduced its West Texas Intermediate (WTI) forecast in 2012 by $5/bbl to $91.50/bbl in 2011, and by $7.50 in 2012 to $85/bbl to reflect “an increase in the projected Brent/WTI spread specific to next year due to delays in pipelines necessary to alleviate the interior North America supply glut. Our overall lower oil price forecast reflects lower economic growth in 2011/2012 than previously anticipated and is modestly amplified by lower developed world oil demand intensity.”

The analysts also cut the 2012 gas price forecast by 50 cents to $4.00/Mcf on the strength of gas-directed and oil well-related gains in the U.S. onshore.

“On the natural gas front, given the likelihood of only modest growth in demand, we believe the shale-driven uplift in gas well productivity compounded by elevated drilling activity and the gas contribution from increased U.S. oil development should leave the gas market meaningfully oversupplied,” said Gerdes. “Consequently, we anticipate a $4 average gas price in 2012.”

The analysts said their research indicates that gas-directed activity next year is expected to be lower by 75 rigs to average 800-850 rigs. They are maintaining a 2013 gas price expectation of $5.00/Mcf, but admitted that it may be an optimistic forecast.

The “gas rig count continues to exhibit astonishing resiliency,” said Gerdes and his colleagues. “The gas rig count is on pace to average 900 rigs this year, which is only 40 rigs less than last year’s average.” In 3Q2011 the gas rig count rose by 50 rigs, with about half of the additions in liquids-rich areas of the Eagle Ford Shale, they noted.