So How Many Gas-Directed Rigs Do We Really Need?
Assuming that the Lower 48 dry gas productivity per gas-directed rig and decline rates are, on average, equal to those in the Barnett Shale, the industry would need to run approximately 550 gas-directed land rigs to sustain the U.S. production at its current level, as discussed in Part II. However, in actuality, the Barnett likely has a higher decline rate than the Lower 48 (although lower than the Marcellus), and therefore, the 550 rig estimate is conservative and overstates the actual requirement.
If all the rigs could be deployed in the most productive dry gas sweet spots, the required rig count would be substantially lower, as discussed in Part I. Assuming that one rig operating in the dry gas "sweet spots" across U.S. gas resource plays can offset declines on 150 MMcf/d base production, the required rig count would be approximately 350 land rigs. Again, this estimate overstates the requirement, as it ignores the lower base decline rate for the Lower 48 portfolio.
Assuming a 30%/70% "dry"/"liquids-rich" mix among the Lower 48 gas-directed land rigs, I arrive at a required rig count range of 475-500 rigs land rigs. I will use this estimate to be conservative, and to avoid presenting more complex calculations that support the lower estimate that takes into account the differentials in decline rates. To this estimate range, I add an estimated 25-50 rigs to capture the gas-directed offshore rig count and land rigs engaged in exploratory programs. The final 500-550 estimated range is comparable to the most frequently quoted Baker Hughes gas directed category for the Lower 48 States. My estimate comes out much lower than what appears to be the prevalent view among analysts and investors.
In this analysis, it is important to also factor in the extensive pre-drilled well inventory that currently exists. Assuming 100 gas wells are brought to sales every month from the backlog industry-wide, such "rigless" supply may be viewed as the equivalent of at least 50 active rigs. The curtailed production due to insufficient infrastructure and, to a lesser extent, voluntary price-driven shut-ins, add an equivalent of another dozen rigs to this and next year's count. Taking into account these two factors, the current 437 gas-directed rig count turns out close to what is needed to maintain the Lower 48 production flat over the next year. Within a year, as many as 100 additional gas-directed rigs may have to be put back to work to avoid production declines.
It is important to note that the Marcellus rig count is, to a great degree, defined by the pace of the infrastructure build out, which has lagged the drilling. Given the remarkably low cost of the Marcellus supply, the production from this field is likely to continue to grow steadily and take the market share from other areas. Therefore the Marcellus rig count is not a true "variable" in the gas supply equation, but rather a function of the off-take capacity additions schedule. It is the rig count in the "second tier" dry gas shale and tight gas plays -- such as the Haynesville, Fayetteville and Pinedale -- that will define the direction of the natural gas supply. Given the still very high productivity of these fields, even a relatively small combined increase in the rig count in these plays (100+ rigs) could have a material impact on gas supply.
- Driven by the remarkable productivity of the dry gas sweet spots, the "new normal" gas-directed rig count required to sustain the U.S. natural gas production at its current level is in the 500-550 rig range, substantially below what appears to have been the prevalent view.
- Once the "rigless" supply contribution from the vast well backlog and production curtailments are taken into account, the current count of 437 gas-directed rigs appears sufficient in the near term for maintaining a flat U.S. production. This conclusion is indirectly supported by the stubbornly resilient recent supply data.
- Given that the current natural gas futures curve provides little incentive to operators to idle additional rigs -- drilling is already economic in dry gas sweet spots -- further improvement in the natural gas fundamentals (i.e., demand beginning to outpace supply) may be problematic in the near future. For the moment, both the rig count and gas price appear to be within the "equilibrium range," with no visible catalysts that could upset this balance.
- Infrastructure build out in the Marcellus shale is an important factor that will continue to impact the U.S. natural gas supply. The growth of the Marcellus contribution to the overall natural gas supply has little dependence on the natural gas prices.
- The continued transition to pad drilling, high-grading of the rig fleet and, most importantly, operators' focus on drilling within the most productive dry gas "sweet spots" will likely continue the trend towards greater rig productivity. As a result, the rig count required to sustain supply at its current level will continue to slowly trend down.
- While the gas-directed rig count has most likely already bottomed, gas drilling activity may not be the driver behind the hoped for improvement in the U.S. land rig utilization. The sustainable demand from gas directed drilling is unlikely to exceed 100 additional rigs. Moreover, this increase in rig demand may take a year to fully materialize. Therefore, the burden of providing tangible incremental demand for the land drilling sector will continue to reside almost entirely with the oil-driven activity.
This discussion of natural gas fundamentals bears relevance to natural gas producer and land drilling stocks.
My natural gas producer index includes:
- Chesapeake Energy (CHK)
- EnCana Corporation (ECA)
- Devon Energy (DVN)
- Southwestern Energy (SWN)
- Ultra Petroleum (UPL)
- EXCO Resources (XCO)
- WPX Energy (WPX)
- Cabot Oil & Gas (COG)
- Range Resources (RRC)
- QEP Resources (QEP)
- Quicksilver Resources (KWK)
- Forest Oil (FST)
- Bill Barrett (BBG)
My land drilling index includes: