Abysmal WTI prices continue to hurt oil producers in the U.S., and that in turn is having a profound effect on state budgets.
Texas, North Dakota, Alaska and Oklahoma are four of the five top oil- and natural gas-producing states and generate a significant share of operating revenues from oil and gas taxes, the U.S. Energy Information Administration (EIA) said.
In December, North Dakota forecasted that oil and gas revenues would be about $8 billion for 2015-2017. After the freefall in prices continued into January, revenues were revised down by $4 billion. On March 18, the North Dakota Office of Management and Budget (OMB) again revised its revenue forecast down by another $1 billion.
Pam Sharp, director of the OMB, said that by statute, only $300 million in oil and gas taxes go to the general fund.
“We’re really in a very good position,” Sharp told Hart Energy. “The general fund is pretty insulated.”
But the state will see an impact on sales and income taxes, she said. Political subdivisions, primarily counties, cities and schools, will see less money. Currently, the state’s production tax is divided so that the state receives 75% and local governments 25%.
“The legislature is working on changing the split to get more money” to local governments, Sharp said.
North Dakota's production tax revenues decreased to $254 million in January from $323 million in August, a 21% drop, the EIA said. Monthly production dipped by about 3% in January.
North Dakota is also plagued by differentials that are, by state calculations, a 15% discount to WTI.
Oil taxes in North Dakota are adjusted if certain triggers are hit based on WTI prices. The state’s 6.5% extraction tax is reduced after five months of prices at depressed levels. If conditions persist for 11 months, the rate falls to 1% or less.
Texas, like North Dakota, has enjoyed the larder opened up by a rejuvenated oil industry.
As the largest oil-producing state, it raked in oil-production tax revenues from 2010-14 of about $11.4 billion and more in natural-gas production tax.
Compared with other boom and bust periods the 40% growth during that stretch was the best growth period since 1972, according to state records.
EIA estimates crude oil and lease condensate production in Texas increased through December, growing to 107 million barrels (MMbbl) from 88 MMbbl from January to December 2014.
The state is now seeing tax revenues decline rapidly.
In February, tax revenues were down 41% from February 2014, a $130 million drop in monthly collections.
Alaska is perhaps most vulnerable to oil prices. The state, which changed its tax code in 2013 to attract more operators, relies on production tax revenue for 90% of its operating budget. More than one-third of Alaska’s jobs are tied to the oil and gas industry.
The state's 2015 revenue projections assumed oil prices at $105, not the $40-$50 prices that have dogged the U.S. market.
According to initial oil and natural gas production tax receipts received by the Alaska Tax Accounting System, monthly oil and gas production tax revenue in August 2014 were $108 million. In January, revenue from the taxes was $26 million, EIA said.
Oil and natural gas production tax represents one of the four primary components of petroleum revenue for the state, with the others being corporate income taxes, property taxes and royalties collected by the Alaska Permanent Fund Corporation.
In February, the Permanent Fund reported it regained 3.2% in its fiscal year 2015 second quarter, largely due to a rally in U.S. stock prices. The Fund was valued at $52.8 billion as of Dec. 31.
In Oklahoma, smaller collections were also seen. In January, Oklahoma tax revenues declined to $43 million, a drop of about 30% from the $62 million from oil and natural gas production taxes in August, EIA said. Oklahoma's production has been relatively flat during that time period.
While California produces more oil than both Alaska and Oklahoma, its economy is much larger, making it relatively less affected by changes in oil and natural gas prices and production, the EIA said.
The deal would create the largest pure-play northern Midland Basin E&P with a 73,000-net-acre position and 12,000 boe/d of production that is expected to more than double through 2020.
Repsol will still hold a 51% stake in the block after the deal.
The March 20 lease sale in the U.S. Gulf of Mexico brought in $244.3 million in high bids.