The Texas Railroad Commission adopted new rules March 26 to encourage Texas operators to continue their efforts to conserve water used in hydraulic fracturing for oil and gas even though hydraulic fracturing and total mining use account for less than one percent of statewide water use. The state’s top three water consumers are irrigation, municipalities, and manufacturing.
Major changes made to the commission’s water recycling rules include eliminating the need for an RRC recycling permit if operators are recycling fluid on their own leases or transferring their fluids to another operator’s lease for recycling. The changes adopted by the commission also clearly identify recycling permit application requirements and reflect existing standard field conditions for recycling permits.
RRC chair Barry Smitherman said, “By removing regulatory hurdles, these new amendments will help foster the recycling efforts by oil and gas operators who continue to examine ways to reduce freshwater use when hydraulically fracturing wells.”
Texas Railroad Commission chair Barry Smitherman, in testimony March 19 before the subcommittee on energy and power of the U.S. House of Representatives Committee on Energy and Commerce, said anti-fossil initiatives by the Environmental Protection Agency threaten the domestic development of abundant and affordable energy from coal and natural gas.
“We now have abundant supplies of natural gas in the United States,” Smitherman said. “Through horizontal drilling and hydraulic fracturing, we have seen a 180-degree turnaround from just five years ago. In late 2008 natural gas prices were at an all-time high, and there was much uncertainty about supply.
“Today the United States is awash in natural gas, but we face a different problem. The EPA, through its anti-fossil, rule-making initiatives, is dramatically limiting America’s ability to burn coal as a means of meeting the growing electricity demands of our homes, businesses and industries.
“Now efforts abound to stop hydraulic fracturing,” Smitherman said. “At the Railroad Commission, we continue to take proactive steps with the intention of implementing industry best practices throughout the hydraulic fracturing process….
“These proactive measures demonstrate that state regulation, which is closest to domestic energy development actions, not a federal one-size-fits-all rule, is the best policy to ensure continued production of abundant and affordable natural gas. The key to keeping our nation’s natural gas momentum going is to limit interference from EPA. Without hydraulic fracturing, our incredible supply of natural gas disappears, prices for gas and electricity skyrocket, and our economy stops dead in its tracks.”
Royal Dutch Shell in February officially began operating in its 2012 acquisition from Chesapeake Energy of 618,000 acres in the Permian Basin. Shell is renovating and rebranding former Chesapeake offices at 2010 Rankin Highway in Midland and returning to the Permian Basin for the first time in about 20 years.
“In the mid-1990s, we divested Permian Basin holdings to a third party as we adjusted our portfolio,” Julie Sacco of Shell told the Midland Reporter-Telegram. “Now we’ve reentered the Permian Basin—also due to adjusting our portfolio.” She said the success of unconventional resource plays also led to Shell’s return. A 2013 drilling program consistent with current levels is planned.
Recent pipeline expansions have helped the Marcellus shale play in the northern Appalachian Basin reach a production rate of more than 7 bcfd to become the largest gas-producing play in the U.S., according to a new IHS Herold Marcellus Shale Company Play Analysis.
Despite a decrease in activity due to weak prices for natural gas, returns in the play remain relatively strong, according to the report written by IHS energy analyst Bryan McNamara. The rig count for 2012 was 1,365—30 percent fewer than the record set in 2011.
Fitch Ratings said anticipated growth in Marcellus gas production likely will mean more long-term business for U.S. midstream companies. Fitch analysts forecast Marcellus production during the next five years will grow to more than 10 bcfd.
In response to increased production in the Permian Basin, Holly Energy Partners said March 7 it will expand its crude oil transportation system in southeastern New Mexico. The announcement by the Dallas-based company indicated that the project has already received the necessary shipper support.
The expansion will provide shippers with additional pipeline takeaway capacity to common carrier pipeline stations for transportation to major crude oil markets or to HollyFrontier’s New Mexico refining facilities. Total capital expenditures are expected to be $35-40 million. Holly Energy Partners anticipates it will be in service by early 2014 with increased capacity of up to 100,000 barrels per day across its system.
The U.S. Energy Information Administration has started using international benchmark Brent crude rather than West Texas Intermediate as the reference price for light sweet crude in its 2013 energy outlooks. The Houston Chronicle said the lingering gap between the prices of WTI and oil produced elsewhere is “complicating the reliability of the longtime benchmark (WTI) as the standard for pricing a barrel of black gold.”
The EIA said it made the change primarily because retail gasoline prices, based largely on the price of crude, more closely follow market fluctuations for Brent rather than West Texas Intermediate. The Chronicle said WTI is higher quality and historically traded at slightly higher prices than Brent, but more recently Brent has sometimes traded more than $25 a barrel higher. The EIA said the January averages were $112.35 for Brent and $94.83 for WTI. The WTI price is depressed by increased shale oil production, pipeline limitations, and storage constraints.
Houston-based NET Midstream will build a 124-mile pipeline to transport natural gas from the Eagle Ford shale into Mexico’s growing energy market. The San Antonio Express News said NET Midstream reached a long-term agreement with MGI Supply, a subsidiary of Mexico’s state-owned gas company, to transport 2.1 billion cubic feet of gas per day.
NET Mexico Pipeline, a subsidiary of NET Midstream, will build the 42-inch pipeline from a hub in Agua Dulce in Nueces County to a point near Rio Grande City in Starr County. Although Mexico has vast reserves of natural gas, the Express-News said, “it hasn’t been able to develop them quickly enough to meet the country’s consumption.” Development will start this year, and the pipeline is expected to come online in December 2014.
Oil and gas exploration and production company Big Sky Petroleum said March 12 it has acquired a 90 percent working interest in 1,100 acres adjacent to its Midland Basin Wolfcamp prospect. This lease acquisition is in addition to the previously announced 2,300 acres acquired by Big Sky in December 2012—on which Big Sky drilled its first well.
Sam Nastat, president, said, “Due to the information we have accumulated from the Schafer No. 1 well, Big Sky is actively seeking to increase its acreage position within this Wolfcamp prospect.”
Capstone Natural Resources Partners said March 14 it has acquired for $50 million oil properties in Andrews and Gaines counties in West Texas as it seeks to expand operations in the central basin. The acquisition of producing assets and associated acreage is from a private seller.
“The newly acquired properties complement our existing asset base perfectly, adding production, cash flow, and low-risk drilling opportunities,” Phil Terry, Capstone CEO, said.
Houston-based Rosetta Resources said March 15 it has reached an agreement to acquire Permian Basin assets from Comstock Resources of Frisco for about $768 million. The acquisition covers 53,306 net acres (87,373 gross) in Reeves and Gaines counties in West Texas.
“This oil-targeted acquisition is an important next step in Rosetta’s strategy to pursue new growth opportunities and build our inventory of long-lived, oil-rich resource projects,” Jim Craddock, chair, CEO, and president of Rosetta, said. “This transaction provides entry into the prolific Permian Basin with both existing production and strong growth potential.”
The Reeves County assets in the Delaware Basin include 40,182 net acres and 74 producing (52 operated) primarily Wolfbone wells. Total net production is about 3,300 barrels of oil equivalent per day (73 percent oil). The Gaines County assets in the Midland Basin cover 13,124 net acres and now are undelineated, and potential exists for multiple exploratory opportunities.
FROM THE RAILROAD COMMISSION OF TEXAS
[issued 28 March 2013]
The Texas average rig count as of March 15, 2013, was 837, representing about 49 percent of all active land rigs in the U.S. In the last 12 months, total Texas reported production was 547 million barrels of oil and 7.2 trillion cubic feet of natural gas.
The commission’s estimated final production for January 2013 is 51,732,068 barrels of crude oil and 497,017,272 MCF (thousand cubic feet) of gas well gas.
The RRC derives final production numbers by multiplying the preliminary January 2013 production totals of 44,238,129 barrels of crude oil and 433,319,330 MCF of gas well gas by a production adjustment factor of 1.1694 for crude oil and 1.1470 for gas well gas. (These production totals do not include casinghead gas or condensate.)
Texas natural gas storage reported to the RRC for February was 316,335,779 Mcf compared to 357,382,948 Mcf in February 2012. The March 2013 gas storage estimate is 301,321,493 Mcf.
The RRC Oil and Gas Division set initial April 2013 natural gas production allowables for prorated fields in the state to meet market demand of 8,665,941 MCF (thousand cubic feet). In setting the initial April 2013 allowables, the commission used historical production figures from previous months and producers’ demand forecasts for the coming month, then adjusted the figures based on well capability. These initial allowables will be adjusted after actual production for April 2013 is reported.
FROM THE U.S. ENERGY INFORMATION ADMINISTRATION
[issued 12 March 2013]
The weekly U.S. average regular gasoline retail price fell in early March for the first time since mid-December. The March 11 average was $3.71 per gallon, down $0.07 per gallon from February 25. EIA expects that lower crude oil prices will result in monthly average regular gasoline prices staying near the February average of $3.67 per gallon over the next few months, with the annual average regular gasoline retail price declining from $3.63 per gallon in 2012 to $3.55 per gallon in 2013 and $3.38 per gallon in 2014. Energy price forecasts are highly uncertain and the current values of futures and options contracts suggest that prices could differ significantly from this forecast.
The EIA expects that the Brent crude oil spot price, which averaged $112 per barrel in 2012 and rose to $119 per barrel in early February 2013, will average $108 per barrel in 2013 and $101 per barrel in 2014. The projected discount of West Texas Intermediate (WTI) crude oil to Brent, which increased to a monthly average of more than $20 per barrel in February 2013, will average $16 per barrel in 2013 and $9 per barrel in 2014, as planned new pipeline capacity lowers the cost of moving mid-continent crude oil to the Gulf Coast refining centers.
U.S. crude oil production exceeded an average level of 7 million barrels per day (bbl/d) in November and December 2012, the highest volume since December 1992. EIA estimates that U.S. total crude oil production averaged 6.5 million barrels per day (bbl/d) in 2012, an increase of 0.8 million bbl/d from the previous year. Projected domestic crude oil production is expected to average 7.3 million bbl/d in 2013 and 7.9 million bbl/d in 2014.
Total U.S. liquid fuels consumption fell from 20.8 million bbl/d in 2005 to 18.6 million bbl/d in 2012. EIA expects total consumption to rise slightly over the next two years to an average of 18.7 million bbl/d in 2014, driven by increases in distillate fuel and liquefied petroleum gas consumption, with little change in gasoline and jet fuel consumption.
Natural gas working inventories ended February 2013 at an estimated 2.08 trillion cubic feet (Tcf), about 0.36 Tcf below the level at the same time a year ago but still 0.27 Tcf greater than the 5-year average (2008-12). EIA expects the Henry Hub natural gas spot price, which averaged $2.75 per million British thermal units (MMBtu) in 2012, will average $3.41 per MMBtu in 2013 and $3.63 per MMBtu in 2014. Current options and futures prices imply that the lower and upper bounds for the 95-percent confidence interval for June 2013 contracts are at $2.79 per MMBtu and $4.67 per MMBtu.
—compiled by Garner Roberts