The Bureau of Labor Statistics (BLS) recently reported that the largest employment increases since the shale revolution commenced circa 2006 occurred in the four U.S. states which just so happened to have the heaviest amount of hydraulic fracturing: North Dakota, Louisiana, Oklahoma, and Texas.
Early estimates suggest that U.S. shale plays will add significant production capacity for years to come:
- Natural gas from shale formations now accounts for 40% of all domestic natural gas production (up from 4% in 2005) with the EIA estimating shale’s share will increase to 53% by 2040
- Reserves: The U.S. possesses an estimated 31 years of AGGREGATE annual natural gas production in shale gas reserves (~15-20% of estimated global shale gas reserves)
- Tight oil accounts for ~12% of current domestic production with this amount expected to reach 17% by 2040
- Reserves: estimated 10 years of AGGREGATE production
With hydraulic fracturing still a relatively new extraction method, we have come across a confusing and wide variation in estimates of two key factors:
- Amount of “Recoverable” Reserves
- Marginal Production Costs
Producers are developing more efficient and useful ways to induce hydraulic fracturing to improve the recovery process. At the end of the day, we expect the rapid evolution of this process to continue, and a constant refresh of those players improving marginal production costs faster than their peers will be key to picking the winners in an environment of low oil and gas prices. Until more research is completed on the possibilities of improving marginal production costs, we can conclude the following:
- Decline rates are very high vs. traditional methods:
- Average decline rate in the world’s conventional oil fields =~5%
- Average decline rates in the Bakken formation =~ 44%
- Average first year decline rates in major U.S. Shale plays =~70%
Available resources and marginal production costs aside for now, what other headwinds threaten the U.S. from fully capitalizing on the Shale Boom?
In this preliminary note on the topic, we’ll begin with recent developments to the current regulatory obstacles impeding our ability to become an exporter of oil and LNG. More extensive analyses surrounding the sustainability of the U.S. shale boom will follow in the coming weeks.
OIL: THE PRESSURE TO LIFT THE EXPORT BAN IS OFFICIALLY HERE
- export ban on oil implemented after the oil embargo in the 1970s
- The Jones Act (1920) requires that oil has to be shipped by Americans in smaller ships:
- It costs around $5-$6 a barrel to ship crude from the Gulf of Mexico to the US east coast on a US-flagged vessel, but only $2 to ship to Canada’s east coast on a foreign-flagged vessel
South Korea and other NATO allies have verbally challenged the U.S. ban on the back of our recent increase in domestic production capacity. Last week the EU’s commissioner for trade, Karel De Gucht, emphasized the need to free up more sources of oil and gas for a wider and more effective free-trade agreement to be instituted.
The Office of the U.S. Trade Representative and the NSC have held internal discussions with the Obama Administration on how to deal with a challenge from the international community. Washington was able to make a national security argument for implementing the ban back when it was importing most of its crude oil, but the added production from the Shale boom is challenging the credibility of that argument.
With added geopolitical tension globally this year, both Asian and European allies are pushing for diversified supply lines. Strengthening their argument, the U.S. just took China to the WTO earlier this year and won a case accusing Beijing of hoarding raw materials and precious metals. Under International Trade rules (General Agreement on Tariffs and Trade), the argument for upholding the restrictions on the exporting of U.S. fossil fuels may be too hypocritical to justify.
We expect a more publicized stance from Washington in Q4.
NATURAL GAS: LNG EXPORT TERMINAL APPROVAL PROCESS MODIFIED IN AUGUST, BUT DEVELOPING ADEQUATE INFRASTRUCTURE FOR INDIVIDUAL PROJECTS LAGS BY 2-3 YEARS.
In August a modification of federal law governing the LNG terminal approval process was implemented. The new rules essentially expedite the FINAL and LAST DOE approval process for those projects that uphold the requirements of NEPA (National Environmental Policy Act) and FERC (onshore)/MARAD (offshore). This will shorten the last step in fully-approving proposed projects:
- Approval required by both FERC/MARAD and NEPA and then finally the DOE (With new rule, DOE gives FINAL approval rather than both CONDITIONAL and FINAL, post-FERC/MARAD approval):
- This change ultimately means that NEPA approval serves to validate what was previously CONDITIONAL DOE approval
- The DOE will now begin evaluating applications 30 days after applications have been scrutinized by NEPA
- NEPA - To meet NEPA requirements federal agencies prepare a detailed statement known as an Environmental Impact Statement (EIS). The EPA reviews and comments on the EISs prepared by other federal agencies, maintains a national filing system for all EISs, and assures that its own actions comply with NEPA
- DOE - For LNG, U.S. law requires export facilities get a "public interest" approval from the DOE if their buyers are located in countries that haven't signed a Free Trade Agreement with the United States. Non-FTA countries include all European nations as well as China, India and Japan.
- The countries without free trade agreements with the United States are considered the most lucrative for LNG exports because many of them have huge appetites for energy
- 31 facilities have applied for DOE permission. Since May 2011, 6 of them (2 in Cameron Parish, La, 1 in Lake Charles, LA, 1 in Texas, 1 in Maryland and 1 in Oregon) have received conditional approval.
- Only the three below have received the final construction go-ahead(NEPA, FERC, and Final DOE approval). Sabine Pass may begin operating as early as the end of next year:
- Sabine Pass (Cheniere Energy) in Louisiana was the first approved and generous estimates are that the end of 2015 for first exporting may be possible
- Cameron Parish (Cameron-subsidiary of Sempra Energy) in Louisiana authorized to export the equivalent of 1.7bn cubic feet/day for a period of 20 years. Project expected to be completed by 2018
- Martin Country (Carib Energy) in Florida expected to be able to export 40M cubic feet/day
The recently approved projects are not expected to be completed until 2017-18. As mentioned above, Sabine may be ready to export by the end of 2015. Stay tuned for additional research that we hope will help stay on top of the most important issues in the shale energy space.
As always, please reach out with comments, questions, or additional color on the most important issues that will make or break the potential of shale’s contribution to domestic production. Have a great night.