When Houston’s Swift Energy Co. reported first-quarter results Thursday, it offered a glimpse at the level of cost-cutting oil and gas companies are making in the Eagle Ford Shale.
“We are seeing cost concessions in some cases greater than we originally budgeted,” said Terry Swift, president and CEO, said in a call with analysts.
Swift’s average drilling cost this year is $2.6 million per well, down from $3.2 million last year. And its most recent Eagle Ford well was drilled for $2.2 million.
Its lease operating costs dropped 16 percent from the previous quarter.
Swift on Thursday reported its first-quarter results. Its Eagle Ford production increased 19 percent over the previous year.
Swift gave an insightful breakdown of what it costs the company to produce oil and get it to market, as well as the level of cost-cutting companies have been making:
The company said it cost $8.48 per barrel of oil to operate its leases in the first quarter of last year. In the first quarter of this year, that dropped to $6.21 per barrel as the company cut costs — “primarily field head count, corporate overhead allocations, and repair and maintenance costs, along with compression and produced water disposal costs.”
Transportation and processing: $1.74 per barrel of oil, down from $1.80.General and administrative expenses of $4.10 per barrel during the first quarter of 2015. That was up $3.57 per barrel from the same months the year before due to “expenses related to a corporate reduction in force” – in other words, layoffs at headquarters.
Interest expense of $5.95 per barrel in the first quarter, down from $6.27 per barrel for the same period in 2014, because of production increases.
Severance and ad valorem taxes were 7.6 percent of oil and gas revenues in the first quarter of 2015, compared to 6.2 percent the year before, due to lower commodity prices.
“We have aggressively sought to reduce our drilling and completion costs for 2015,” said Bob Banks, executive vice president and chief operating officer at Swift, in a call with analysts. “We have negotiated lower prices for goods and services, including chemicals, trucking, labor rates, saltwater disposal costs, and some of the examples of the cost reductions on our lease operating expenses include both labor and repairs and maintenance costs, each by over $200,000 a month from 2014 levels. Additionally, compression costs are down over $150,000 a month compared to 2014 levels.”
Swift officials said they think this lower-cost environment could be here for some time.
In all, Swift realized an average price of $21.99 per barrel of oil equivalent during the quarter, down from $50.62 in the first quarter of 2014.
The company has one drilling rig in South Texas now. It drilled four wells in Webb County in the first quarter and one in McMullen County.http://fuelfix.com/blog/2015/05/08/swift-details-how-costs-are-dropping-in-the-eagle-ford/
Seemingly, the industry is adapting well to the change in the commodity price environment. However, a word of caution is in order.
The breakeven price is highly sensitive to the discount rate and "cost overburdens" included in the calculation.
A case can be made that a higher discount rate should be used in the current environment as capital is scarce and more expensive. Cost overburdens per well have also increased as activity contracted.
- To illustrate, consider a company that in 2014 ran 20 rigs and spent $1.6 billion in capex, with G&A expenses of $160 million.
- Let's assume that the same company is now running 5 rigs, with a capex run-rate of $300 million, G&A expense of $140 million and restructuring charges of $60 million.
- The math shows that the company's direct cost per well has dropped by 25%.
- However, if one were to include the G&A overburden in the calculation, the well cost would be unchanged. If one were to also include the restructuring charges, the calculation would show that the cost per well has gone up by ~14%.
- In this specific illustration, the improvement in drilling returns, if any, would be from eliminating less promising drilling locations from the drilling plan. Moreover, the improvement would be offset in part by the increase in the cost of capital.
The above example illustrates that while it may appear that well economics have improved dramatically relative to a year ago, the comparison is not always "apples to apples":
- The wells being compared are not the same;
- Cost of capital is not the same;
- Vendor cost reductions are very significant but reflect a different point in the cycle and may not be sustainable; and
- Cost savings at the well level are diminished by higher non-D&C costs per well.