State wants gas sale info for Prudhoe plan; owners estimate 20K-60K barrel decline

  • BP (Exploration) Alaska President Janet Weiss stands alongside Gov. Bill Walker at a Feb. 17 press conference when the state and its three North Slope partners on the Alaska LNG Project announced a delay in progressing the effort because of low oil prices. BP, the operator of Prudhoe Bay, is being asked a series of detailed questions by state regulators regarding major gas sales before they will approve the 2016 development plan for the field. Photo/Elwood Brehmer/AJOC

Editor's note: BP submitted a letter to the Division of Oil & Gas May 2 correcting its decline estimate from 20,000 to 60,000 barrels per day to 0 to 40,000 barrels per day.

The state Division of Oil and Gas wants significantly more information from Prudhoe Bay field operator BP and its fellow working owners on how a scaled-back work plan for this year could impact prospects for a gasline down the road.

Oil and Gas Director Corri Feige wrote a letter to senior BP Alaska officials April 11 asking more than a dozen technical questions related to a major gas sales project including drilling plans, management of carbon dioxide pulled from Prudhoe natural gas, gas balancing agreements and efforts to market the gas.

BP’s 2016 Prudhoe Bay Plan of Development, or POD, submitted to the division March 31 included its estimates for production decline after it idles several rigs and reduces its well workovers this year.

BP stated the lost drilling time could result in a production decline of between 20,000 barrels and 60,000 barrels per day.

The Plan of Development focuses on drilling work for oil recovery but only briefly and very generally touches on preparing for gas offtake, currently planned to support the Alaska LNG Project. AK LNG is a $45 billion-plus project involving the State of Alaska and major North Slope producers BP, ConocoPhillips and ExxonMobil who are the working interest owners at Prudhoe.

“The (Prudhoe Bay Unit) working interest owners will continue to evaluate viable plans and incorporate into the current plan of development to further optimize gas and oil recovery, and to address facilities, equipment, wells and operational changes to position for major gas sales,” the development plan states.

Feige indicated that the division wouldn’t approve the plan without the additional information it requested, writing that “absent this further detail, the Division cannot evaluate whether the POD meets regulatory critieria.”

The letter asked for responses by May 1.

Oil and gas unit annual development plan deadlines are based when the unit was originally formed and therefore do not follow a strict calendar year.

Now-retired Department of Natural Resources Commissioner Mark Myers sent a letter to unit operators across the state in January notifying them that future unit development plans will need to include the additional information.

Myers wrote that DNR is “working proactively to ensure maximum development and monetization of Alaska’s energy resources.” Consequently, the state needs to understand how all hydrocarbons available for offtake are being used, sold within the state or prepped for future sale, according to Myers.

Feige said in an interview that it is the administration’s priority to use that information to determine if there is gas that could be captured for in-state use. Commercially sensitive information would be kept confidential, she added.

Anything learned from Cook Inlet basin natural gas producers could be used to “think outside the box” about how the state can possibly help find or generate new markets for Inlet gas, according to Feige.

Limited demand for Inlet gas has been the primary impediment to increased production from the basin in recent years and led to fears of supply shortages in 2012.

The division is anticipating “pretty broad-brush responses” to set a baseline of information that can be added to each year, she said.

“For the state and certainly for the division it’s about understanding the resource in a unit that may be available, timeframes, maximizing the oil and when do we start looking at and thinking about those future production resources,” Feige said.

The Journal obtained the letters and development plan late April 26 and a BP Alaska spokesperson could not be reached for comment in time for this story.

Regarding marketing, the state asked BP to provide “the identity of the parties with whom the current commercial agreement(s) are being negotiated, or with whom each WIO intends to have substantive discussions regarding the marketing of unit hydrocarbons including unit gas, and the commercial terms under which each WIO is offering to make resources available for long-term sale, including: the estimated volumes to be delivered, the pricing terms, the location at which title to the gas and associated risks of loss will change, and the condition of gas at the time of delivery.”

Feige called specific references in the April 11 letter to marketing efforts for major gas sales an “unintended consequence” of wording, noting that the original state lease forms grant lessees rights for exploration, development, production, process and marketing of oil and gas from the lease area.

DNR and the division attempted to stay consistent with the lease language in their request and are not trying to use regulatory authority to gather information for the state’s role in the Alaska LNG Project.

“The existence of that firewall between the Division of Oil and Gas and the AK LNG project is absolutely rock solid and it has to be,” Feige said. “We are absolutely prohibited from discussing, sharing information, etcetera and we obviously at the division, we’ve got to live hard and fast by that firewall because the work that we do is built on relationships and it’s built on a whole lot of trust.”

The correspondence between the state and BP references “major gas sales” but not a specific project to sell gas.

She said the division has been in contact with unit operators to clear confusion about exactly what information it wants going forward.

“It’s an iterative process and what (BP) submitted the first time just lacked a bunch of that technical information about how do we manage the field to get (to major gas sales)” Feige said.

Prudhoe production drop

The Prudhoe Bay development plan also lays out BP’s expectations for how its idling of three drill rigs will impact production from the country’s largest oil field.

BP projects the reduced drilling time — 3.8 rig years in 2015 to 1.6 rig years in 2016 — will result in a production decline of 20,000 barrels to nearly 60,000 barrels of oil per day from the Prudhoe Bay field.

The nearly 40 year-old field produced an average of 196,400 barrels of oil per day in 2015.

A rig year is the cumulative time drilling rigs are operating in a given field. Two rigs operating for 182 days each, for example, would roughly equal one rig year.

Well workover activity will be cut as well, from 27 workovers in 2015 to just 4 this year.

Unsurprisingly, BP cited the current price environment as the reason for reducing activity in the field. The company announced in early March that it would reduce the number of rigs working at Prudhoe from five to two this year.

Companywide, BP reported a $1.2 billion loss from production activities in the first quarter. It’s average first quarter sale price for Alaska North Slope crude was $34 per barrel. The current average cost to produce and ship North Slope oil is about $46 per barrel, according to the state Revenue Department.

The Department of Revenue’s latest production forecast released April 7 does not appear to include the expected Prudhoe decline detailed in the development plan submitted to the Division of Oil and Gas March 31.

The preliminary spring forecast released March 21 projected daily North Slope production to average 517,700 barrels per day in fiscal year 2016 and 507,100 barrels per day in 2017. The revised April 7 forecast actually increased expected 2016 production to 520,200 barrels per day and kept the 2017 forecast at 507,100 barrels.

The 2017 state fiscal year starts July 1, so a drop in calendar year 2016 production would likely show up in both fiscal year forecasts.

Department officials said they could not discuss specifically what information the forecast is based on to air on the safe side of confidentiality requests from the companies, but said the forecast is an aggregate of what companies expectations are.

Elwood Brehmer can be reached at [email protected].

Updated: 
05/06/2016 - 2:05pm