Elwood Brehmer

Showdown set over oil tax credit bills

At long last, oil tax credit reform legislation has passed both the House and the Senate. The issue, however, is still far from resolved. Despite technically being the same bill, House Bill 247 that passed the House May 13 is vastly different than the version of HB 247 that passed the Senate by a 14-6 vote on May 18, the last day of the session allowed under the state Constitution. The differences between the bills will have to be resolved in a conference committee, which will require either a 10-day extension of the current session if two-thirds of both houses agree, or a special session called by either the Legislature or Gov. Bill Walker. The bottom line budget impact of the Senate version would save and generate up to roughly $160 million per year once its provisions were fully implemented by 2019, according to Revenue Department estimates. The tax credit changes in the House bill approach $280 million in benefit to the state by fiscal year 2020, when it would take full effect. Regardless of changes to the future credit program, the state is still on the hook for about $775 million of earned credits that need to be paid in fiscal year 2017 — an expense that still needs to be added to the operating budget. That includes the $200 million Gov. Bill Walker vetoed from last year’s tax credit payment, which was in practice a veto, but in actuality a payment deferral. At the time Walker said the action was to “start a conversation” about the credit program that he and many legislators have said is unsustainable when the state is $4 billion in the hole. It worked. The hotly debated legislation stalled progress on other key revenue bills in the last weeks of the session. The impasse on the House side was seemingly overcome with the passage of its HB 247, but the Senate’s bill, passed on day 121, has likely added another high hurdle. Both versions of HB 247 would reduce the value of refundable credits for eligible capital expenses incurred by companies working in Cook Inlet in 2017 and wholly eliminate Cook Inlet refundable tax credits in 2018. The Senate bill would also add a tax to Cook Inlet oil of up to $1 per barrel, roughly equivalent to the 17.5-cent per thousand cubic feet, or mcf, tax on that exists on Inlet gas. It would be the first production tax on Inlet oil in roughly 20 years. The differences — and certain points of contention when legislators attempt to resolve them — mostly lie in credits applicable to companies working on the North Slope. The House version of HB 247 would immediately eliminate the current 35 percent Net Operating Loss, or NOL, credit for companies producing more than 15,000 barrels per day. The ability for large producers to carry annual losses incurred during periods of low oil prices or high investment and apply those losses against future tax liabilities was also stripped. For those small, remaining NOL-eligible Slope producers, the Net Operating Loss credit would ramp down from 35 percent to 25 percent by 2023. Additionally, the House version would institute a 5 percent minimum “tax floor” when the yearly average price of Alaska North Slope crude hits $70 per barrel. The Walker administration’s original HB 247 would have raised the minimum tax from 4 percent established by the production tax structure known as Senate Bill 21 to 5 percent. Industry and Republican-led majority caucus legislators contended the proposed tax increase would be a major change to Senate Bill 21, which Walker has said he was not interested in doing after voters upheld in the law in a 2014 referendum before he was elected. The current tax floor can be “pierced” by companies applying the NOL and other credits to their tax liability during times of low prices — an unintended consequence of not modeling the impact of SB 21 in low-price scenarios. The Senate version of HB 247 would not change the 35 percent NOL credit for North Slope companies. By eliminating refundable credits from the Cook Inlet basin, the only refundable credit available to companies in the producing areas of the state would be the North Slope NOL for small producers. Both bills would limit companies to $70 million of refundable, or cashable, credits per year. The per company limit has swung in the many versions of credit legislation from a low of $25 million in the administration’s tax credit proposal to as high as $200 million in House Resources. The Senate HB 247 complicates the cap slightly by allowing companies to receive full payment for the first $35 million of applied credits; the state would pay the second $35 million installment at 75 percent of face value unless the company chooses to carry the second half of its credits to a future year. Current law has no per company limit for refundable credits. Both bills also complicate the 20 percent Gross Value Reduction credit that is applicable to oil produced from new wells. They end the deductible GVR credit seven years after first production from a new well or after three years — consecutive or not — of an Alaska North Slope crude price of at least $70 per barrel. “New oil” is currently eligible for the GVR indefinitely, which the governor’s bill did not address. Numerous committee versions of tax credit legislation jumped between five-year and 10-year GVR limits. Credit confidentiality The House version of HB 247 would allow the Revenue Department to disclose which companies receive refundable credits and the amount they are reimbursed. The Senate version would allow the department to annually report how much the state spent reimbursing each type of credit, but the names of the companies receiving the credits would be kept confidential. A floor amendment by Sen. Bill Wielechowski, D-Anchorage, to change the Senate bill to mirror House language was voted down. Republican Sens. Peter Micciche and Bill Stoltze broke from Majority ranks on that vote and supported the amendment. Currently law limits the department to aggregating the total annual credit amounts paid by the basin in which they were earned. Industry has said the companies receiving credits needs to remain confidential to protect private tax information. House and Senate Minority caucus members have rebutted that accepting the credits are optional, and therefore companies can choose whether or not they want to accept the subsidy or keep the information confidential.  

State affirms demand for marketing info in Prudhoe plan

Simply put, the State of Alaska wants information about potential North Slope natural gas sales the big three producers are not willing to hand over. Alaska Division of Oil and Gas Director Corri Feige sent a letter to BP Alaska management May 12 reiterating that the 2016 Plan of Development for the Prudhoe Bay will be considered incomplete until the company shares “specific information” regarding its efforts to market North Slope gas in preparation for a gasline project. BP operates Prudhoe Bay on behalf of ConocoPhillips and ExxonMobil, the field’s other primary working interest owner companies. The May 12 letter is the latest correspondence in a back-and-forth between the producers and the state that dates back to early in the year. In January, now-retired Department of Natural Resources Commissioner Mark Myers wrote the first letter to BP on the issue stating the department, which houses the Division of Oil and Gas, would be requesting new technical and marketing information related to prospective “major gas sales” in future unit plans of development. Similar letters were sent to each oil and gas unit operator across Alaska with the aim of improving the state’s knowledge bank regarding how it can help get the currently stranded gas resources to in-state or export markets, according to DNR officials. BP firmed up its position 10 days earlier in a letter to the division contending the new Plan of Development “requirement is outside the scope of current regulations and constitutes impermissible rulemaking,” BP Alaska Reservoir Manager Scott Digert wrote May 2. The division must go through the formal public regulatory process to appropriately change what is required in unit Plan of Development, Digert added. “In order to adequately evaluate how the (Prudhoe Bay Plan of Development) meets the requirements of (state regulations) and other law, the division needs specific information regarding past and on-going efforts to market gas in both the local and non-local markets,” Feige wrote in the May 12 letter. “To the extent it is contemplated at this time, the division also needs specific commitments and timelines regarding how gas will be marketed in the future. The division acknowledges the various objections raised by BP and ConocoPhillips regard the division’s requests and, again, respectfully disagrees.” If the Plan of Development is not approved, an appeal to the division’s ruling would likely be heard by the Alaska Oil and Gas Conservation Commission. The state is an equal-share partner in the $45 billion-plus natural gas export effort known as the Alaska LNG Project with BP, ConocoPhillips and ExxonMobil. While roughly three-quarters of the gas reserves to feed the AK LNG Project would come from Prudhoe Bay, the prodigious oil and gas field would undoubtedly be the main driver behind any major North Slope gas sales. BP’s 2016 Prudhoe Bay Unit Plan of Development submitted March 31 focused on immediate plans to recover oil from the field and contained only a couple vague paragraphs about its ongoing efforts to support a gas project. It told the division that each working interest owner company would have to submit its own gas marketing information to avoid anti-trust issues among the potentially competing parties. The current Prudhoe Bay Plan of Development expires June 30, according to the division. ConocoPhillips responded to an April 11 letter from Feige on May 4 stating its support of BP’s position and offering a bilateral meeting with division officials to understand the demands for information. ExxonMobil has not responded to the division, a fact noted in Feige’s May 12 letter. An ExxonMobil Alaska spokesperson told the Journal the company would defer to BP as the unit operator on the issue. Elwood Brehmer can be reached at [email protected]  

Alaska delegation asks Kerry to review transboundary mining

Alaska’s congressional delegation responded to continued concerns from Southeast Alaskans about Canadian mine plans by asking Secretary of State John Kerry to look into whether environmental practices across the border are worthy of scrutiny under a bilateral treaty. Rep. Don Young and Sens. Lisa Murkowski and Dan Sullivan sent a letter to Kerry May 12 requesting the State Department to question Canadian officials about the impact active and proposed hard rock mines in British Columbia and the Yukon could have on salmon in several large “transboundary” rivers. “Like most Alaskans, we strongly support responsible mining, including mines in Southeast Alaska, but Alaskans need to have every confidence that mining activity in Canada is carried out just as safely as it is in our state,” the delegation wrote. “Yet, today, that confidence does not exist. “Proposed mining development in the Stikine, Taku River, and Unuk watersheds has raised concerns among commercial and recreational fishermen, tourism interests, and Alaska Native communities regarding water quality maintenance of the transboundary rivers that flow by their homes and onto their fishing grounds.” The letter references seven active or planned mines just on the British Columbia side of the border from Southeast Alaska. It specifically notes that the long-closed underground Tulsequah Chief metal mine in the Taku drainage northeast of Juneau has been leaking acidic wastewater into the river for many years. Late last year, Canadian government officials finalized efforts to reduce the leakage but did not require the mine’s water treatment facility be restarted. There have also been proposals to reopen the Tulsequah Chief project. Also last November, Gov. Bill Walker and British Columbia Premier Christy Clark signed a non-binding memorandum of understanding, or MOU, to establish a Bilateral Working Group on the Protection of Transboundary Waters. The Alaska side of the group, tasked with facilitating an exchange of best practices, marine safety and joint visitor industry promotion among other things, is led by Lt. Gov. Byron Mallott. The delegation did not go as far as to ask for action by the International Joint Commission, or IJC, which was established in 1909 to resolve disputes over how actions in one country could impact watersheds shared by both. It did, however, urge Kerry to “utilize all measures at your disposal to address this issue at the international level” and decide if the “IJC is a suitable venue to determine whether Canadian mines are following ‘best practices’” for wastewater and mine tailings treatment. Also highlighted in the delegation’s letter is a British Columbia Auditor General report released earlier this month that is highly critical of the province’s oversight of mining activity. Additionally, it asked for a more formal consultation process with state agencies, Tribes, and Alaska Native corporations during Canadian mine permit reviews. While numerous Alaska environmental, commercial fishing, and Alaska Native groups have called for IJC involvement, the commission can only be spurred by a formal call from either the State Department or Canada’s Global Affairs Department. Those groups lauded the delegation in formal statements reacting to the letter. “This powerful statement underscores that Alaskans, regardless of political party, want Secretary Kerry to address (British Columbia) mining with Canadian officials so that clean water and healthy salmon runs will support our economy for generations to come,” Salmon Beyond Borders director Heather Hardcastle said. Originally, IJC intervention was intended only when both governments submit a “letter of referral” asking for the commission to resolve a dispute. Over time that procedure has morphed and both countries have at times singularly requested IJC involvement, which has often been granted. The commission’s recommendations are nonbinding but generally adhered to in an effort to maintain a cooperative relationship between the countries. Throughout its history the IJC has been intensely involved in water and air quality issues related to development along Canada’s border with the Lower 48. However, it has never ruled on or heard a water-related contention regarding the Alaska-Canada border, according to a statement on its website. British Columbia Minister of Energy and Mines Bill Bennett has said in interviews with the Journal and the Juneau Empire that the issues are not with the province’s environmental regulations and enforcement, but rather with better communicating with Alaskans how thoroughly British Columbia monitors its mines. The province has taken significant heat for the Mount Polley mine tailings dam failure in 2014, which a government investigation concluded was caused by design flaws. B.C. regulatory report British Columbia Auditor General Carol Bellringer pulled no punches in a lengthy report released May 3 calling for an overhaul of the province’s environmental regulation enforcement practices. “We found almost every one of our expectations for a robust compliance and enforcement program within the (Ministry of Energy and Mines) and the (Ministry of Environment) were not met,” Bellringer wrote in comments on the report. “We found major gaps in resources, planning and tools. As a result, monitoring and inspections of mines were inadequate to ensure mine operators complied with requirements. The ministries have not publicly disclosed the limitations with their compliance and enforcement programs, increasing environmental risks, and government’s ability to protect the environment.” The 109-page report plainly entitled, “An Audit of Compliance and Enforcement of the Mining Sector,” recommends the responsibility to enforce environmental regulations be pulled from the Ministry of Energy and Mines. The ministry is also tasked with promoting resource development, which Bellringer described as being “diametrically opposed” to its regulatory enforcement mandate. As a result, the report recommends British Columbia establish an independent compliance and enforcement unit for mining activities to ensure environmental protection. The report also contends Energy and Mines relies too heavily on individuals referred to as “qualified professionals” — industry’s technical experts that are trusted to monitor the mine construction and operation. “It is not (the Ministry of Energy and Mines’) practice to carry out its own technical review [or to oversee an independent technical review] to confirm that tailings dams are built in accordance with the design and technical standards,” the report states. Provincial government officials retorted in a response included in the report that the audit team failed to clarify what regulatory compliance and enforcement programs should be measured against. Government’s response also pushed back against the charge that Energy and Mines officials cannot handle the responsibility of both promoting and regulating the mining industry. “We do not accept that mere appearances are sufficient to warrant the act of removing compliance and enforcement from (Energy and Mines),” government officials wrote. “No one is more aware of the need to find the appropriate balance between promotion and regulation of mining in ministry decision-making than those who are asked to do so on a daily basis.”

Showdown set over oil tax credits

At long last, oil tax credit reform legislation has passed both the House and the Senate. The issue, however, is still far from resolved. Despite technically being the same bill, House Bill 247 that passed the House May 13 is vastly different than the version of HB 247 that passed the Senate by a 14-6 vote on May 18, the last day of the session allowed under the state Constitution. The differences between the bills will have to be resolved in a conference committee, which will require either a 10-day extension of the current session if two-thirds of both houses agree, or a special session called by either the Legislature or Gov. Bill Walker. The bottom line budget impact of the Senate version would save and generate up to roughly $160 million per year once its provisions were fully implemented by 2019, according to Revenue Department estimates. The tax credit changes in the House bill approach $280 million in benefit to the state by fiscal year 2020, when it would take full effect. Regardless of changes to the future credit program, the state is still on the hook for about $775 million of earned credits that need to be paid in fiscal year 2017 — an expense that still needs to be added to the operating budget. That includes the $200 million Gov. Bill Walker vetoed from last year’s tax credit payment, which was in practice a veto, but in actuality a payment deferral. At the time Walker said the action was to “start a conversation” about the credit program that he and many legislators have said is unsustainable when the state is $4 billion in the hole. It worked. The hotly debated legislation stalled progress on other key revenue bills in the last weeks of the session. The impasse on the House side was seemingly overcome with the passage of its HB 247, but the Senate’s bill, passed on day 121, has likely added another high hurdle. Both versions of HB 247 would reduce the value of refundable credits for eligible capital expenses incurred by companies working in Cook Inlet in 2017 and wholly eliminate Cook Inlet refundable tax credits in 2018. The Senate bill would also add a tax to Cook Inlet oil of up to $1 per barrel, roughly equivalent to the 17.5-cent per thousand cubic feet, or mcf, tax on that exists on Inlet gas. It would be the first production tax on Inlet oil in roughly 20 years. The differences — and certain points of contention when legislators attempt to resolve them — mostly lie in credits applicable to companies working on the North Slope. The House version of HB 247 would immediately eliminate the current 35 percent Net Operating Loss, or NOL, credit for companies producing more than 15,000 barrels per day. The ability for large producers to carry annual losses incurred during periods of low oil prices or high investment and apply those losses against future tax liabilities was also stripped. For those small, remaining NOL-eligible Slope producers, the Net Operating Loss credit would ramp down from 35 percent to 25 percent by 2023. Additionally, the House version would institute a 5 percent minimum “tax floor” when the yearly average price of Alaska North Slope crude hits $70 per barrel. The Walker administration’s original HB 247 would have raised the minimum tax from 4 percent established by the production tax structure known as Senate Bill 21 to 5 percent. Industry and Republican-led majority caucus legislators contended the proposed tax increase would be a major change to Senate Bill 21, which Walker has said he was not interested in doing after voters upheld in the law in a 2014 referendum before he was elected. The current tax floor can be “pierced” by companies applying the NOL and other credits to their tax liability during times of low prices — an unintended consequence of not modeling the impact of SB 21 in low-price scenarios. The Senate version of HB 247 would not change the 35 percent NOL credit for North Slope companies. By eliminating refundable credits from the Cook Inlet basin, the only refundable credit available to companies in the producing areas of the state would be the North Slope NOL for small producers. Both bills would limit companies to $70 million of refundable, or cashable, credits per year. The per company limit has swung in the many versions of credit legislation from a low of $25 million in the administration’s tax credit proposal to as high as $200 million in House Resources. The Senate HB 247 complicates the cap slightly by allowing companies to receive full payment for the first $35 million of applied credits; the state would pay the second $35 million installment at 75 percent of face value unless the company chooses to carry the second half of its credits to a future year. Current law has no per company limit for refundable credits. Both bills also complicate the 20 percent Gross Value Reduction credit that is applicable to oil produced from new wells. They end the deductible GVR credit seven years after first production from a new well or after three years — consecutive or not — of an Alaska North Slope crude price of at least $70 per barrel. “New oil” is currently eligible for the GVR indefinitely, which the governor’s bill did not address. Numerous committee versions of tax credit legislation jumped between five-year and 10-year GVR limits. Credit confidentiality The House version of HB 247 would allow the Revenue Department to disclose which companies receive refundable credits and the amount they are reimbursed. The Senate version would allow the department to annually report how much the state spent reimbursing each type of credit, but the names of the companies receiving the credits would be kept confidential. A floor amendment by Sen. Bill Wielechowski, D-Anchorage, to change the Senate bill to mirror House language was voted down. Republican Sens. Peter Micciche and Bill Stoltze broke from Majority ranks on that vote and supported the amendment. Currently law limits the department to aggregating the total annual credit amounts paid by the basin in which they were earned. Industry has said the companies receiving credits needs to remain confidential to protect private tax information. House and Senate Minority caucus members have rebutted that accepting the credits are optional, and therefore companies can choose whether or not they want to accept the subsidy or keep the information confidential.  

Stalemate between state, producers continues over Prudhoe plan

Simply put, the State of Alaska wants information the big three producers are not willing to hand over about potential North Slope natural gas sales. Alaska Division of Oil and Gas Director Corri Feige sent a letter to BP Alaska management May 12 reiterating that the 2016 Plan of Development for the Prudhoe Bay will be considered incomplete until the company shares “specific information” regarding its efforts to market North Slope gas in preparation for a gasline project. BP operates Prudhoe Bay on behalf of ConocoPhillips and ExxonMobil, the field’s other primary working interest owner companies. The May 12 letter is the latest correspondence in a back-and-forth between the producers and the state that dates back to early in the year. In January, now-retired Department of Natural Resources Commissioner Mark Myers wrote the first letter to BP on the issue stating the department, which houses the Division of Oil and Gas, would be requesting new technical and marketing information related to prospective “major gas sales” in future unit plans of development. Similar letters were sent to each oil and gas unit operator across Alaska with the aim of improving the state’s knowledge bank regarding how it can help get the currently stranded gas resources to in-state or export markets, according to DNR officials. BP firmed up its position 10 days earlier in a May 2 letter to the division contending the new Plan of Development “requirement is outside the scope of current regulations and constitutes impermissible rulemaking,” BP Alaska Reservoir Manager Scott Digert. The division must go through the formal public regulatory process to appropriately change what is required in unit Plan of Development, Digert added. “In order to adequately evaluate how the (Prudhoe Bay Plan of Development) meets the requirements of (state regulations) and other law, the division needs specific information regarding past and on-going efforts to market gas in both the local and non-local markets,” Feige wrote in the May 12 letter. “To the extent it is contemplated at this time, the division also needs specific commitments and timelines regarding how gas will be marketed in the future. The division acknowledges the various objections raised by BP and ConocoPhillips regard the division’s requests and, again, respectfully disagrees.” The state has a 25 percent share in the $45 billion-plus natural gas export effort known as the Alaska LNG Project with BP, ConocoPhillips and ExxonMobil. Roughly three-quarters of the gas reserves to feed the AK LNG Project would come from Prudhoe Bay, and the prodigious oil and gas field would undoubtedly be the main driver behind any major North Slope gas sales. BP’s 2016 Prudhoe Bay Unit Plan of Development submitted March 31 focused on immediate plans to recover oil from the field and contained only a couple paragraphs about its ongoing efforts to support a gas project. It told the division that each working interest owner company would have to submit its own gas marketing information to avoid anti-trust issues among the potentially competing parties. The current Prudhoe Bay Plan of Development expires June 30, according to the division. ConocoPhillips responded to the April 11 letter from Feige on May 4, asserting its support of BP’s position and offering to meet with the Division of Oil and Gas about the information requested. ExxonMobil has not responded to the division, a fact noted in Feige’s May 12 letter. An ExxonMobil Alaska spokesperson has told the Journal the company would defer to BP as the unit operator on the issue. Look for updates to this story in an upcoming issue of the Journal. Elwood Brehmer can be reached at [email protected]

Delegation asks Kerry for transboundary review

Alaska’s congressional delegation responded Thursday to continued concerns from Southeast Alaskans about Canadian mine plans by asking Secretary of State John Kerry to look into whether environmental practices across the border are worthy of attention under a bilateral treaty. Rep. Don Young and Sens. Lisa Murkowski and Dan Sullivan sent a letter to Kerry May 12 requesting the State Department to question Canadian officials about the impact active and proposed hard rock mines in British Columbia and the Yukon could have on salmon in several large “transboundary” rivers. “Like most Alaskans, we strongly support responsible mining, including mines in Southeast Alaska, but Alaskans need to have every confidence that mining activity in Canada is carried out just as safely as it is in our state,” the delegation wrote. “Yet, today, that confidence does not exist. Proposed mining development in the Stikine, Taku River, and Unuk watersheds has raised concerns among commercial and recreational fishermen, tourism interests, and Alaska Native communities regarding water quality maintenance of the transboundary rivers that flow by their homes and onto their fishing grounds.” The letter references seven active or planned mines just on the British Columbia side of the border from Southeast Alaska. It specifically notes that the long-closed underground Tulsequah Chief metal mine in the Taku drainage northeast of Juneau has been leaking acidic wastewater into the river for many years. Late last year, Canadian government officials finalized efforts to reduce the leakage but did not require the mine’s water treatment facility be restarted. There have also been proposals to reopen the Tulsequah Chief project. In November, Gov. Bill Walker and British Columbia Premier Christy Clark signed a non-binding memorandum of understanding, or MOU, to establish a Bilateral Working Group on the Protection of Transboundary Waters. The Alaska side of the group, tasked with facilitating an exchange of best practices, marine safety and joint visitor industry promotion among other things, is led by Lt. Gov. Byron Mallott. The delegation did not go as far as to ask for action by the International Joint Commission, or IJC, which was established in 1909 to resolve disputes over how actions in one country could impact watersheds shared by both. It did, however, urge Kerry to “utilize all measures at your disposal to address this issue at the international level” and decide if the “IJC is a suitable venue to determine whether Canadian mines are following ‘best practices’” for wastewater and mine tailings treatment. Additionally, it asked for a more formal consultation process with state agencies, tribes and Alaska Native corporations during Canadian mine permit reviews. While numerous Alaska environmental, commercial fishing and Alaska Native groups have called IJC involvement, the commission can only be spurred by a formal call from either the State Department or Canada’s Global Affairs Department. Those groups lauded the delegation in formal statements reacting to the letter. “This powerful statement underscores that Alaskans, regardless of political party, want Secretary Kerry to address (British Columbia) mining with Canadian officials so that clean water and healthy salmon runs will support our economy for generations to come,” Salmon Beyond Borders director Heather Hardcastle said. Also highlighted in the letter is a British Columbia Auditor General report released earlier this month that is highly critical of the province's oversight of mining activity. British Columbia Minister of Energy and Mines Bill Bennett has said in interviews with the Journal and the Juneau Empire that the issues are not with the province’s environmental regulations and enforcement, but rather with better communicating with Alaskans how thoroughly British Columbia monitors its mines. The province has taken significant heat for the Mount Polley mine tailings dam failure in 2014, which a government investigation concluded was caused by design flaws. Elwood Brehmer can be reached at [email protected]

Producers reject state demand for details on gas sales

The major North Slope producers and state regulators have considerable differences of opinion regarding what information the state can demand in oilfield development plans. BP sent a letter to the Division of Oil and Gas May 2 contending that its Prudhoe Bay Plan of Development for 2016 satisfies the requirements in the 1977 Prudhoe Bay Unit Agreement and all state regulations regarding unit development plans. The company did not provide the detailed technical and marketing information about potential “major gas sales” — a gasline project — that Oil and Gas Director Corri Feige wrote in an April 11 letter that the division would need to approve the plan. “The division’s (April 11) letter seeks extraordinary additional information concerning ‘the timing and type of activities that will be conducted to prepare for major gas sales,’” BP Alaska Reservoir Manager Scott Digert wrote. “These new requirements asserted by the division are contrary to the terms of the (Prudhoe Bay Unit Agreement) as well as the division’s regulations and the division’s own interpretation of its regulations over many decades.” ConocoPhillips Prudhoe Area Manager Jon Schultz wrote to the division May 4 that the company supports BP’s May 2 letter. BP is the operating company for Prudhoe Bay; ConocoPhillips and ExxonMobil are working interest owners in Prudhoe. Schultz wrote that the company proposes to meet and discuss the requests to “avoid potential confusion and miscommunication between ConocoPhillips and the division, which could conceivably impact other confidential discussions between ConocoPhillips and the DNR and give rise to other issues.” The ConocoPhillips letter concludes, “At this point, our goal is to understand the context, intent and purpose of the division’s request.” In a statement, the Division of Oil and Gas said it “appreciates the companies’ responses and is review all of the data and information that has been provided.” BP’s March 31 development plan told the division the company could not speak about efforts made to market Prudhoe natural gas by the other working interest owners. Prudhoe Bay and Point Thomson, which is operated by ExxonMobil, are the fields from which the proposed $45 billion-plus Alaska LNG Project would draw natural gas. The companies and the division use the generic term “major gas sales,” referring to any potential gasline project. The division forwarded the BP and ConocoPhillips letters to the Journal after a records request for all responses to the April 11 letter. ExxonMobil appears not to have responded to the division. ExxonMobil spokeswoman Kim Jordan said the company would defer all questions on the issue to BP as the Prudhoe unit operator. Now-retired DNR Commissioner Mark Myers wrote letters in January to all oil and gas unit operators in the state notifying them that the department would be asking for new information in future development plans. When a brief general reference to BP’s work on major gas sales in the Prudhoe Bay plan did not suffice, Feige responded with the more specific April 11 request. She said in an interview that the division expected the new information to be “pretty broad-brush responses” to help the state establish baseline knowledge about how the operational transition from oil production to major gas sales from the Slope fields would work. When asked for his input on the issue a spokeswoman for Gov. Bill Walker said it would not be appropriate for him to comment on the apparent impasse because it is a regulatory issue. Unit operators typically must submit development plans 90 days prior to the annual plan expiration date. The 2015 Prudhoe Bay plan expires June 30. Development plan years start and end based on when the unit in question was formed and thus do not align with the calendar year. Elwood Brehmer can be reached at [email protected]

Bank backing Anchorage LIO warns Legislature to stay put

An attorney for the bank that financed the Anchorage Legislative Information Office building made it clear in a May 10 letter that the Legislature will not walk away from the building without once again going to court over the matter. Jacksonville, Fla.-based EverBank wrote through its local legal counsel Robert Hume of Landye Bennett Blumstein LLP that it will sue the state for violating the subordination, non-disturbance and attornment agreement signed by an internal attorney for the Legislature, Rep. Mike Hawker and the bank in December 2014, just after the LIO construction project was completed. Mark Pfeffer, managing partner of the building owner group 716 West Fourth Avenue LLC, also signed the agreement, or SNDA. Hawker chaired the Legislative Council at the time. The bank contends the SNDA is its contract with the Legislative Affairs Agency that binds the agency to its obligations associated with the building regardless of extenuating circumstances. EverBank made its $28.6 million loan to 716 based on the assurance that the Legislative Affairs Agency would honor the 10-year lease it signed to rent the Downtown Anchorage office space. It would not have made the loan if the agency had not entered into the SNDA, according to the letter. The Legislative Affairs Agency handles business and legal matters for the Legislature. With a year-plus of the lease paid, EverBank estimates it would seek $27.5 million from the state. “In addition, if EverBank is required to institute an action to recover damages from the state, under the SNDA EverBank is entitled to recover its litigation costs,” the letter states. On May 2, the Legislative Council voted to negotiate a purchase of Wells Fargo’s Midtown Anchorage office building for up to $12.5 million on the grounds that Gov. Bill Walker said he would veto a $32.5 million purchase of the Anchorage LIO that was included in the state capital budget. The amended capital budget released May 11 included $12.5 million for the Wells Fargo building and removed the funding for the LIO. Walker said it is inappropriate for the Legislature to spend millions of dollars on an office building while the state is cutting services to reconcile its $4 billion budget deficit. “EverBank demands that the (Legislative Affairs Agency) reaffirm and establish that the tenant lease is in full force and effect, valid and binding on the state, and cease any and all efforts to invalidate the tenant lease, vacate the property, or secure alternate lease premises,” Hume wrote. “This is a serious matter,” Hume concluded. “Please give it immediate attention.” The Anchorage Assembly also weighed in on the matter May 10, passing a resolution urging the Legislature not to relocate its Anchorage offices outside of downtown because the move would conflict with the city’s land use plan, and by extension, could potentially violate state law requiring agencies to abide by local planning and zoning ordinances. Legislators first took action to move out of the LIO in December after bowing to public scrutiny over the $3.3 million per year lease to occupy the offices that were custom-built for the Legislature. At that time, the Legislative Council passed a motion to move to the nearby state-owned Atwood Building unless a cost-competitive solution to stay could be found. After several months of wrangling, the cost-competitive solution appeared to be the purchase of the building — approved at a March 31 council meeting — which would also satisfy EverBank’s needs by allowing 716 to repay its debt. As is common practice for large construction projects, EverBank’s loan refinanced the short-term construction loan 716 secured for the $44.5 million project from Wells Fargo and Northrim Bank. 716 spokeswoman Amy Slinker referenced a previous letter from the Alaska Bankers Association in a formal statement. The letter generally said leaving the LIO and breaking the lease would put the State of Alaska’s trustworthiness in jeopardy in the eyes of the financial industry. “EverBank describes this as a ‘serious matter.’ If the state breached an agreement with a substantial financial institution, it would be hard to quarrel with EverBank’s characterization given the consequences that would follow. We trust that the state will review this matter with the high level of care and caution it warrants,” Slinker wrote. “A review of the EverBank letter makes it clear that the comments by the Alaska Bankers Association would no longer be hypothetical. A breach by the state likely would trigger a reassessment by lenders of the state’s credit risk and an increase in interest rates for state projects. The long-term cost to the state could dwarf the financial issues associated with the LIO.” EverBank’s May 10 letter cites a section of the SNDA that states the Legislature has no “defense against rental due or to become due under the terms of the lease.” The bank also argues that even though the lease between the Legislature and 716 was ruled invalid in state Superior Court in March because the council violated state procurement code in obtaining the lease, the SNDA still obligates the state to make EverBank whole. “If the tenant lease is invalid, as ruled in the McKay order, then each of the express representations made by the LAA to EverBank described above are and were false,” Hume wrote. 716 and Legislative Affairs filed motions requesting Judge Patrick McKay reconsider his ruling. If he does not and the lease is once again deemed invalid, then the SNDA was signed under false pretense and the Legislature is exposed to EverBank, according to the letter. Pfeffer has also said 716 would sue the Legislature if it walks away from the building. In its motion for reconsideration filed May 6, the Legislative Affairs Agency argues that if the lease is deemed invalid, the court would also need to consider whether the Legislature is entitled to get back some or all of the $7.5 million in tenant improvements it agreed to pay as part of the deal the Legislative Council negotiated with 716 in 2013. Elwood Brehmer can be reached at [email protected]

Seventh rewrite of tax credit bill gets hearing in House

The House Rules Committee met May 10 on the hope that the seventh version of oil and gas tax credit reform would be the compromise numerous other committees and the administration were unable to reach. The latest iteration of House Bill 247 cuts the credit program just a little deeper than the previous two versions tested by the Rules Committee over the past three weeks. It ends the refundable credit program to new entrants to the Cook Inlet basin immediately; however, companies with oil or natural gas production in the Inlet this year would be eligible for capital expenditure and net operating loss credits that would be completely phased out by the end of 2018. Drastically cutting the oil and gas tax credit program that has become the state’s third largest budget line item is a foundational piece of the administration’s New Sustainable Alaska Plan to solve the $4 billion budget deficit by fiscal year 2019. House Rules chair Rep. Craig Johnson, R-Anchorage, said he believes the bill “strikes a balance” between reducing the state’s immediate expenses and cutting credits and increasing taxes on the industry to the point of deterring future business. “What we don’t want to do is trim (credits) back so bad that we’re not open for business any longer,” Johnson said. Tax Division Director Ken Alper characterized it as “a $300 million bill” in combined annual savings and increased revenue once its changes are fully implemented by fiscal year 2020. For North Slope operators, the existing refundable 35 percent Net Operating Loss credit that has garnered much attention with oil at low prices would be limited to very small producers, those with less than 15,000 barrels of production per day, and companies with current plans to explore or develop projects on the Slope. That select group of companies could receive the NOL credit through 2019, at which point it would be eliminated. After 2019, all companies would adhere to the more traditional method of deducting one year’s operating losses against future tax liabilities. Previous Rules Committee versions of HB 247 allowed companies with up to 20,000 barrels per day to continue to get the refundable NOL credit before it was phased out. Large producers, those with more than 50,000 barrels per day, must currently deduct operating losses incurred at times of low oil prices or high investment, or both, against future tax liabilities. HB 247 would eventually implement that mechanism on all companies on the Slope. Ending the refundable NOL credit would establish a true tax “floor” by not allowing deductions to reduce a company’s tax obligation below the 4 percent minimum production tax. The Department of Revenue estimates a 4 percent minimum production tax could raise up to $100 million per year in tax revenue once the NOL is fully eliminated. Legislators on both sides of the debate have conceded the impact of refundable NOL credits on the minimum tax during low oil price periods — such as now — was not considered while the industry-supported oil tax reform known as Senate Bill 21 was vetted and passed in 2013. At that time oil prices were consistently near $100 per barrel. Janak Mayer, chairman of the Legislature’s consultant firm Enalytica, testified May 10 that the NOL credit being refundable as cash is “somewhat unique” among oil and gas regimes. In broader terms, Mayer said the latest HB 247 is a major improvement over the administration’s credit reform package because it is much less sudden. “Crucially, the bill holds the existing credit system in place until the end of the year,” he said. “That’s important because numerous companies have entered into solid contracts from now until the end of the year for work programs in part for drilling and other capital work premised on the basis of receiving these credits.” Regardless of the look of the final legislation, in fiscal year 2017 the State of Alaska will still have to pay upwards of $775 million of refundable credits that companies have already earned. Credits for exploration in “Middle Earth” Alaska— areas of the state other than Cook Inlet or the North Slope — would be maintained. Alaska Oil and Gas Association President and CEO Kara Moriarty testified at a May 11 Rules meeting that reducing incentives and raising taxes on the industry that supports thousands of jobs and a vast majority of the state budget at a time when the industry is struggling with low oil prices will do nothing to benefit the future of the state. “We recognize that many of you are looking for ways to fill the state’s budget cap and see increasing taxes on the oil industry as part of the solution,” Moriarty said to the committee. “However, to be completely candid, the (bill) in question will result in disastrous long-term economic consequences to our state that will far outweigh the temporary and modest short-term gains.” She noted that the royalty revenue the state would lose if North Slope production declines at the rate projected by the Revenue Department — with no tax change —would eventually negate much of the savings the state would see as a result of the HB 247. Reversing the production decline curve, as has been done in fiscal year 2016, requires stable, not reactionary policies, Moriarty said. “It is simply a mathematical calculation. Numbers dictate investment, and a bill like this makes the numbers worse. End of story,” she said. The earlier Rules bills also set an $85 million per company per year cap on refundable credits. The latest bill lowered the cap to $75 million. The per-company refundable limit has varied widely as the legislation has evolved through the committee process. Gov. Bill Walker’s credit bill introduced at the start of the session set a $25 million cap; House Resources put it at $200 million; House Finance tried $100 million; Senate Resources first floated the $85 million cap that was adopted by House Rules, which has now dropped it to $75 million. A 10-year limit on the 20 percent Gross Value Reduction, or GVR, credit applied to oil produced from new fields has been in each Rules Committee substitute. Current tax law allows companies producing oil from new fields to use the GVR to reduce the wellhead value of that oil by 20 percent forever, which in turn lowers the taxable value of that oil. The administration’s bill did not address the GVR, but other committees ended it after five years of production, which, according to Mayer, could strain the viability of many projects and would essentially be the same as eliminating it altogether. Mayer said the 10-year term limit on the GVR is a significant improvement over the five-year expiration, but could still impact the financial viability of some developments. Mayer said elimination of the GVR could wipe out the economic value of a project at $60 per barrel, and that eliminating NOL credit refunds for developments would increase the need for private capital by more than 50 percent and require an increase in price of $10 per barrel to generate an attractive rate of return. Elwood Brehmer can be reached at [email protected]

AOGA at 50: A half-century of discoveries, and déjà vu

A select group of people has had the opportunity to watch Alaska grow along with one of its trademark industries from the inside out. Marilyn Crockett is one of those people. As a former leader of the Alaska Oil and Gas Association, she, and the others that have held that position, had the unique task of representing a diverse group of companies — including some of the largest businesses in the world — as one. AOGA will mark its 50th anniversary May 25 with a special daylong event at the Dena’ina Civic and Convention Center in Anchorage. Crockett “went to work pounding a typewriter” for AOGA as a 17-year-old secretary when it was still the Alaska Division of the Western Oil and Gas Association, she said. She retired as executive director just four years ago after holding nearly every position in the organization. “I’m not going to lie; I needed a job and that was one of the interviews that I got. I stayed through all the years because it was a fascinating place to work because I got to work for all the oil and gas companies,” she recalled. “It was fascinating to be in the trade association and watch all the different dynamics of the different companies, whether they were producers, refiners or explorers.” The name change came a few years later. AOGA’s membership has continued to reflect the industry in the state. Current President and CEO Kara Moriarty said the association had upward of 40 members in the 1980s and 17 when she was hired about a decade ago. AOGA currently has 10 member companies: seven producers, two refineries and Alyeska Pipeline Service Co., which operates the Trans-Alaska Pipeline System. Crockett was hired by Bill Hopkins, who had taken leadership of the association not long after being hired himself in January 1969 and was responsible for public relations duties. He was hired by Bill Bishop, a former Richfield Oil Corp. geologist that helped discover the Swanson River oilfield on the Kenai Peninsula, Alaska’s first modern-day oil and gas field. “Those were pretty rocking times,” Hopkins said. The history-altering discovery of Prudhoe Bay had been made a year prior and the budget-altering first North Slope lease sale that would net the state more than $900 million on Sept. 10, 1969, was yet to come. (That equates to a $5.8 billion lease sale for about 412,000 acres in today’s dollars.) Hopkins called it “Prudhoe mania.” “All of a sudden everyone’s speaking in terms of billions,” he said. To the south, the Cook Inlet and Kenai Peninsula oil and gas fields were growing and the industry and Alaskans were learning how to get along. Before joining the association Hopkins worked as the Southcentral liaison for Gov. Bill Egan. The job acquainted him with the industry managers and also schooled him in the residents’ concerns about local hire and environmental issues, making him a well-suited mediator between the two. One of the first messages he had to relay was that trash could not be tossed over the side of the new platforms in Cook Inlet. Commercial salmon fishermen complained about catching pallets and empty concrete bags in their nets. “To the guys on the platforms, Cook Inlet just looked like muddy water that came in on the high tide and went out on the low tide,” Hopkins explained. Environmental practices in the oil and gas industry have certainly changed; Alaska is a model for environmental stewardship and the best practices developed by North Slope companies have been adopted by other industries and other oil and gas regions, Crockett noted. However, other issues haven’t evolved much. “Prudhoe came along at a time when already the public and in particular the politicized portion of the public saw the oil industry as all money and no people,” Hopkins said. “(The companies) were generating large revenues to the state and the more populous-thinking folks said, ‘Well why don’t we get 90 percent and they only get 10 percent? It’s our oil,’ kind of forgetting that there’s a contract stating how much of the oil was whose.” Though a registered lobbyist, the stiff competition between companies meant Hopkins’ role was at first was more that of a messenger than a representative for the industry as a whole. Companies that were targets for increased taxation or regulation didn’t want a third party, or worse yet their competitors, to speak on their behalf, he said. “I acted a lot as a referee, but mostly as an information channel,” to assure the companies weren’t, “being played against each other by the hammerheads in the Legislature,” he quipped. When U.S. Vice President Spiro Agnew cast the deciding vote in the Senate to pass the Trans-Alaska Pipeline Authorization Act on July 17, 1973, Alaskans were ready to get to work on the project that would reroute the history of their state. “I can remember sitting in my office just after TAPS was authorized and seeing who I knew were construction workers coming down the hall because they saw our sign on the building and thought we were the hiring hall for TAPS and we’d have to send them on their way,” Crockett said. Since Prudhoe began production in 1977, one of AOGA’s biggest missions has been to educate new Alaskans about the reason they don’t pay personal taxes for the services they receive and actually get a check each year from their government, she said. The state income tax was repealed in 1980 as the oil boom began. Crockett is particularly proud of the economic impact studies AOGA has led that illustrate the importance of an industry that is often out-of-sight and out-of-mind to the economic health of the state. She said the association has done a “stellar job” educating people about the role the industry that even in today’s tough times supports more than 12,000 well-paying jobs and has historically accounted for nearly 90 percent of state revenue. Hopkins, who retired from AOGA in 1993, said he still gets a pleasant reminder of his time in Alaska now and then even though he has since moved to Idaho. “Every time I go into my walk-in closet I’ve got a helmet up there — a white helmet with my name on it for the 10th anniversary of the operation of the trans-Alaska Pipeline — and every time I see that thing it kind of gives me a warm feeling that I was just lucky to be a witness, if not a great mover and shaker, of the whole thing,” he said. “I was quite peripheral but I was right there watching the people that were really doing it.” Crockett referred to the current debate over industry tax credits that has ground progress in the Legislature to a halt for weeks as “déjà vu all over again.” Despite the challenges today, she said she still has high hopes for the industry and the state, citing the doubling of Cook Inlet oil production in recent years as an example of what can still happen in Alaska when policy matches market. “I think, largely thanks to the Legislature providing incentives for those Cook Inlet companies, we now have production back up, which I think a lot of folks thought would never happen again,” she said. Current AOGA head Moriarty concurred. “The good news is the rocks aren’t going anywhere,” she said. “But will there be policies in place from a local, state and federal level to allow companies to utilize their expertise to develop those resources?” Elwood Brehmer can be reached at [email protected]

Bank backing Anchorage LIO warns Legislature to stay put

An attorney for the bank that financed the Anchorage Legislative Information Office building made it clear in a May 10 letter that the Legislature will not walk away from the building without once again going to court over the matter. Jacksonville, Fla.-based EverBank wrote through its local legal counsel Robert Hume of Landye Bennett Blumstein LLP that it will sue the state for violating the subordination, non-disturbance and attornment agreement signed by an internal attorney for the Legislature, Rep. Mike Hawker and the bank in December 2014, just after the LIO construction project was completed. Mark Pfeffer, managing partner of the building owner group 716 West Fourth Avenue LLC, also signed the agreement, or SNDA. Hawker chaired the Legislative Council at the time. The bank contends the SNDA is its contract with the Legislative Affairs Agency that binds the agency to its obligations associated with the building regardless of extenuating circumstances. EverBank made its $28.6 million loan to 716 based on the assurance that the Legislative Affairs Agency would honor the 10-year lease it signed to rent the Downtown Anchorage office space. It would not have made the loan if the agency had not entered into the SNDA, according to the letter. The Legislative Affairs Agency handles business and legal matters for the Legislature. With a year-plus of the lease paid, EverBank estimates it would seek $27.5 million from the state. “In addition, if EverBank is required to institute an action to recover damages from the state, under the SNDA EverBank is entitled to recover its litigation costs,” the letter states. On May 2, the Legislative Council voted to negotiate a purchase of Wells Fargo’s Midtown Anchorage office building for up to $12.5 million on the grounds that Gov. Bill Walker said he would veto a $32.5 million purchase of the Anchorage LIO that was included in the state capital budget. The amended capital budget released May 11 included $12.5 million for the Wells Fargo building and removed the funding for the LIO. Walker said it is inappropriate for the Legislature to spend millions of dollars on an office building while the state is cutting services to reconcile its $4 billion budget deficit. “EverBank demands that the (Legislative Affairs Agency) reaffirm and establish that the tenant lease is in full force and effect, valid and binding on the state, and cease any and all efforts to invalidate the tenant lease, vacate the property, or secure alternate lease premises,” Hume wrote. “This is a serious matter,” Hume concluded. “Please give it immediate attention.” The Anchorage Assembly also weighed in on the matter May 10, passing a resolution urging the Legislature not to relocate its Anchorage offices outside of downtown because the move would conflict with the city’s land use plan, and by extension, could potentially violate state law requiring agencies to abide by local planning and zoning ordinances. Legislators first took action to move out of the LIO in December after bowing to public scrutiny over the $3.3 million per year lease to occupy the offices that were custom-built for the Legislature. At that time, the Legislative Council passed a motion to move to the nearby state-owned Atwood Building unless a cost-competitive solution to stay could be found. After several months of wrangling, the cost-competitive solution appeared to be the purchase of the building — approved at a March 31 council meeting — which would also satisfy EverBank’s needs by allowing 716 to repay its debt. As is common practice for large construction projects, EverBank’s loan refinanced the short-term construction loan 716 secured for the $44.5 million project from Wells Fargo and Northrim Bank. 716 spokeswoman Amy Slinker referenced a previous letter from the Alaska Bankers Association in a formal statement. The letter generally said leaving the LIO and breaking the lease would put the State of Alaska’s trustworthiness in jeopardy in the eyes of the financial industry. “EverBank describes this as a ‘serious matter.’ If the state breached an agreement with a substantial financial institution, it would be hard to quarrel with EverBank’s characterization given the consequences that would follow. We trust that the state will review this matter with the high level of care and caution it warrants,” Slinker wrote. “A review of the EverBank letter makes it clear that the comments by the Alaska Bankers Association would no longer be hypothetical. A breach by the state likely would trigger a reassessment by lenders of the state’s credit risk and an increase in interest rates for state projects. The long-term cost to the state could dwarf the financial issues associated with the LIO.” EverBank’s May 10 letter cites a section of the SNDA that states the Legislature has no “defense against rental due or to become due under the terms of the lease.” The bank also argues that even though the lease between the Legislature and 716 was ruled invalid in state Superior Court in March because the council violated state procurement code in obtaining the lease, the SNDA still obligates the state to make EverBank whole. “If the tenant lease is invalid, as ruled in the McKay order, then each of the express representations made by the LAA to EverBank described above are and were false,” Hume wrote. 716 and Legislative Affairs filed motions requesting Judge Patrick McKay reconsider his ruling. If he does not and the lease is once again deemed invalid, then the SNDA was signed under false pretense and the Legislature is exposed to EverBank, according to the letter. Pfeffer has also said 716 would sue the Legislature if it walks away from the building. In its motion for reconsideration filed May 6, the Legislative Affairs Agency argues that if the lease is deemed invalid, the court would also need to consider whether the Legislature is entitled to get back some or all of the $7.5 million in tenant improvements it agreed to pay as part of the deal the Legislative Council negotiated with 716 in 2013. Elwood Brehmer can be reached at [email protected]

Slope producers rebuff state demand for gas sale info

The major North Slope producers and state regulators have considerable differences of opinion regarding what information the state can demand in oilfield development plans. BP sent a letter to the Division of Oil and Gas May 2 contending that its Prudhoe Bay Plan of Development for 2016 satisfies the requirements in the 1977 Prudhoe Bay Unit Agreement and all state regulations regarding unit development plans. The company did not provide the detailed technical and marketing information about potential “major gas sales” — a gasline project — that Oil and Gas Director Corri Feige wrote in an April 11 letter that the division would need to approve the plan. “The division’s (April 11) letter seeks extraordinary additional information concerning ‘the timing and type of activities that will be conducted to prepare for major gas sales,’” BP Alaska Reservoir Manager Scott Digert wrote. “These new requirements asserted by the division are contrary to the terms of the (Prudhoe Bay Unit Agreement) as well as the division’s regulations and the division’s own interpretation of its regulations over many decades.” ConocoPhillips Prudhoe Area Manager Jon Schultz wrote to the division May 4 that the company supports BP’s May 2 letter. BP is the operating company for Prudhoe Bay; ConocoPhillips and ExxonMobil are working interest owners in Prudhoe. Schultz wrote that the company proposes to meet and discuss the requests to “avoid potential confusion and miscommunication between ConocoPhillips and the division, which could conceivably impact other confidential discussions between ConocoPhillips and the DNR and give rise to other issues.” The ConocoPhillips letter concludes, “At this point, our goal is to understand the context, intent and purpose of the Division’s request.” BP’s March 31 development plan told the division the company could not speak about efforts made to market Prudhoe natural gas by the other working interest owners. Prudhoe Bay and Point Thomson, which is operated by ExxonMobil, are the fields from which the proposed $45 billion-plus Alaska LNG Project would draw natural gas. The companies and the division use the generic term “major gas sales,” referring to any potential gasline project. The division forwarded the BP and ConocoPhillips letters to the Journal after a records request for all responses to the April 11 letter. ExxonMobil appears not to have responded to the division. Now-retired DNR Commissioner Mark Myers wrote a letter to all oil and gas unit operators in the state notifying them that the department would be asking for new information in future development plans. When a brief general reference to BP’s work on major gas sales in the Prudhoe Bay plan did not suffice, Feige responded with the more specific April 11 request. She said in an interview that the division expected the new information to be “pretty broad-brush responses” to help the state establish baseline knowledge about how the operational transition from oil production to major gas sales from the Slope fields would work. Unit operators typically must submit development plans 90 days prior to the annual plan expiration date. The 2015 Prudhoe Bay plan expires June 30. Development plan years start and end based on when the unit in question was formed and thus do not align with the calendar year. Look for updates to this story in an upcoming issue of the Journal. Elwood Brehmer can be reached at [email protected]

BP corrects 20K-barrel error in Prudhoe production estimate

BP is asking the state to correct a 20,000-barrel per day error in its 2016 production estimate for the Prudhoe Bay oil field. The company submitted a letter to the Division of Oil and Gas May 2 stating the production forecast range included in the 2016 Prudhoe Bay Plan of Development submitted March 31 is off by 20,000 barrels per day for what BP actually believes its average daily production from the field will be this year. BP is the Prudhoe Bay operator for the field’s other working interest owner companies, primarily ConocoPhillips and ExxonMobil. The original development plan stated the average total crude and condensate production rate from Prudhoe is estimated at 137,000 to 176,000 barrels per day in 2016, which would be a 20,000 to 60,000 barrel decrease from the more than 196,000 barrels per day the field produced last year, according to the plan document. The corrected 2016 forecast in the May 2 letter is 157,000 to 196,000 barrels of oil and condensate per day — a forecast range of flat production to a decline of 40,000 barrels per day year-over-year. Additionally, BP asked to amend its expectation for natural gas liquid, or NGL, production from Prudhoe from 29,000 to 37,000 barrels per day in the original plan to 36,000 to 45,000 barrels of NGLs per day. BP declined to comment on how the error occurred; however, sources close to the situation said it was simply a “typo” and that the lower forecast numbers were in prior year development plans and mistakenly were not revised in the 2016 plan. The development plan states BP’s active rig time will be “significantly reduced compared to 2015 due to the sharp reduction in oil prices” over the past couple years. Well workover activity will be cut as well, from 27 workovers in 2015 to just 4 this year, according to the development plan. BP announced in March that it would be cutting the number of drill rigs working in the Prudhoe Bay field from five to two this year because of the sustained oil price drop. Elwood Brehmer can be reached at [email protected]

AG hires lawyer who advised threatening leases

A former Alaska Gasline Port Authority legal consultant with historically hard line views on producers’ obligations under state oil and gas leases is now working for the Department of Law on those issues. Mark Cotham, a Houston-based attorney, was hired by the Department of Law in July 2015 as a contract attorney with expertise “in obligations of oil and gas lessees to develop leases,” according to his contract with the department. His original contract, not to exceed $65,000, ran through June 30, 2016; it was amended earlier this year to run through June 30, 2017, with a $130,000 limit. Cotham testified to the Legislative Budget and Audit Committee in 2005 that he was “struck” by the lack of discussion about the producers’ requirement to develop and sell natural gas from state leases in his research into the relationship between the State of Alaska and the North Slope producers. At the time, the state was working to advance an ultimately unsuccessful North Slope natural gas project under Stranded Gas Development Act. In November 2006, Cotham wrote an opinion column for the Juneau Empire entitled “My turn: Speaking in terms Big Oil can grasp: Lease cancellation threats may get companies talking.” With the state administration in flux during the 2006 election season, he described his views on how the companies should be treated by whomever led a gasline project for the state. “The central point that the new gas pipeline negotiator must make to the oil companies is that they do not have the legal, let alone the moral, right to hold Alaska’s gas hostage to their own profit targets,” Cotham wrote. “If getting that point across involves a lawsuit to cancel their leases, so be it. If it takes a few years to get a court determination, that is certainly shorter than the oil companies’ proposed ‘study’ under the current proposal. And after that wait, Alaska stands a very good chance of owning, ‘lock stock and barrel,’ the North Slope leases and 100 percent of the gas.” Gov. Bill Walker is a former project manager and general counsel for the Alaska Gasline Port Authority, which Cotham was representing in his 2005 testimony to the Legislature. The authority was formed to develop a gasline from the Slope to Valdez for in-state use and export. Attorney General Craig Richards is a former attorney in Walker’s law firm and for the authority. Walker’s chief of staff Jim Whitaker is a former mayor of Fairbanks and former chair of the authority. Whitaker also co-authored the sponsor statement for a 2006 ballot measure to institute a reserves tax on North Slope gas as a means to spur development. Walker floated a gas reserves tax before last November’s special session but withdrew the idea soon after. In a Jan. 14 letter, now-retired Department of Natural Resources Commissioner Mark Myers wrote a letter to BP Alaska officials informing the company that the department wanted information regarding efforts to market oil and gas from the Prudhoe Bay unit included in future unit development plans. Division of Oil and Gas Director Corri Feige said in an interview that similar letters were sent to all unit operator companies in the state because it is a priority of the administration’s to have the information for possibly developing gas for instate use. BP’s Prudhoe Bay Plan of Development submitted March 31 focused mainly on immediate drilling plans and included a general statement that, “Major gas sales (MGS) from Prudhoe Bay remains depended upon a number of factors, including market demand and the availability of an acceptable offtake project. In the meantime, the Prudhoe Bay unit working interest owners will continue to use gas to enhance and accelerate oil recovery and for (natural gas liquids) production for shipment through TAPS or use in enhanced oil recovery operations.” Feige followed with an April 11 letter to BP stating the Prudhoe Bay development plan is “not sufficient to allow the division to understand how the (working interest owners) plan to achieve an MGS.” The letter also stated that the division could not consider the plan complete from a regulatory standpoint until it received additional information. The letter subsequently requested detailed information regarding commercial agreements being negotiated for natural gas sales from the Prudhoe unit as well as “the commercial terms under which each (working interest owner) 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 the associated risks of loss will change, and the condition of the gas at the time of delivery.” In recognition of BP’s statement that the working interest owners preferred to do their marketing individually, the Oil and Gas Division asked for responses to the April 11 letter from BP as the Prudhoe operator and ConocoPhillips and ExxonMobil to be submitted by May 1. That deadline was extended one day to May 2. The Journal submitted a public records request to the division for the publicly available portions of the producers’ responses May 3; the request was not granted as of press time for this story. State agencies have 15 business days to respond to such requests. Look for updates to this story in an upcoming issue of the Journal and at www.alaskajournal.com. Elwood Brehmer can be reached at [email protected]  

LIO saga continues with vote to buy Midtown office space

Would the Legislature make for a good landlord? Most of the Legislative Council seems to think so. The council voted 12-1 on May 2 in favor of purchasing a Midtown Anchorage office building owned and occupied by Wells Fargo bank for $12.5 million and turning it into the Anchorage Legislative Information Office. According to documents from the meeting, which was mostly held in executive session, Wells Fargo would lease-back space on the ground floor of the four-story office building after the sale. The bank currently runs a branch out of the first floor and occupies space on the third and fourth floors of the 1500 West Benson Blvd. address. Legislative Council Chair Sen. Gary Stevens, R-Kodiak, now has 60 days from the vote to negotiate a deal with Wells Fargo, per the council motion to approve the purchase. Barely a month prior, the council voted 13-1 to purchase the current Downtown Anchorage LIO for $32.5 million, a vote that seemingly signaled an end to the self-inflicted political melodrama that has been fueled by public outcry over the terms of the rental agreement approved in 2013 by then-Legislative Council chair and now outgoing Anchorage Republican Rep. Mike Hawker. Minority caucus members in both chambers of the Legislature have also jumped on the criticism bandwagon, contending the $3.3 million per year lease rate for the Downtown LIO is exorbitant at a time when the state is cutting services from nearly every agency to mitigate a $4 billion budget deficit. Ample criticism has also stemmed from the procurement process used to reach the deal that spurred construction of the Anchorage LIO. While a formal competitive-bid process was not used, Anchorage real estate developer and managing member of the building owner group Mark Pfeffer has repeatedly noted that the council requested proposals for LIO space numerous times over several years. When office space compatible with the Legislature’s needs for size, location, public access and parking among other requirements was not offered, the six-story, $44.5 million building custom-made for legislators was erected. Wells Fargo funded the part of the construction loan for the LIO built in 2014 along with Northrim. The construction loans were eventually consolidated into a single longterm note by EverBank based in Jacksonville, Fla. If Wells Fargo would stay as a tenant in the Legislature’s building it could generate up to $225,000 per year in rent and moving Legislative Audit staff into the building when the agency’s lease expires in 2022 could save another $53,000 per year, according to council documents. At the same time, buying the building for $12.5 million means the Legislature would eat its $7.5 million equity investment in the current LIO. Including the first year’s rent through May 31, the Legislature’s outlays for LIO space Downtown and at the Wells Fargo building would top $24 million. Staff for Stevens circulated an informal memo to all 60 legislators dated April 7 that included a dozen “bullet points” as to why the council agreed to buy the current Anchorage LIO for $32.5 million. Among the reasons for the deal are the points that it would meet the criteria of a December motion because it is financially comparable to the cost of moving to the nearby state-owned Atwood Building, which houses executive branch agencies. The memo also states that, “Buying the building honors our commitment with the owners of the building,” and “It alleviates the concerns by the business community and investors about the state backing out of a lease and a possible downgrade of the state’s credit rating.” When the council first considered moving from the LIO to the Atwood Stevens and other legislators said they believed they could do so without recourse because contracts with the state contain a “subject to appropriation” clause that essentially voids the contract if the Legislature does not fund it. Administration Commissioner Sheldon Fisher told the council March 31 that much of the space legislators thought they could move into at the Atwood would not be available until January 2018. The sudden about-face was spurred by Gov. Bill Walker threatening to veto a purchase of the Downtown Anchorage building, which was included in the Senate version of the capital budget as a $32.5 million line item appropriation. The Legislative Council’s May 2 motion to move on the Wells Fargo property directly cited Walker’s veto stance on the $32.5 million LIO purchase. The Associated Press reported April 14 that Walker said buying office space doesn’t jive with the state’s financial situation. He was less definitive during an April 27 press briefing, saying he had been talking with legislators about the LIO situation and that it was “too soon to respond” to a question regarding whether he would veto any proposed building purchase. An Alaska Superior Court judge voided the Legislature’s 10-year lease on the building in late March, ruling the council violated state procurement code by not opening the project — deemed by the court to be new construction and not a remodel of the former smaller LIO on the site — to bids. However, the state has been found liable for government contractors’ expenses in historical cases in which agencies breached procurement procedure and private firms executed work on the reliance that the state handled its business properly. Pfeffer has indicated that the LIO building owner group, 716 West Fourth Avenue LLC, would sue the Legislature if it walks away from the building. 716 first proposed to sell the property for $37 million to recover its cost in the project, according to Pfeffer, but ultimately agreed to a $32.5 million price. “We did what the Legislature asked us to do. Now we’re just asking them to honor their commitment,” Pfeffer said in an interview. A December 2014 subordination and non-disturbance agreement needed for EverBank to approve long-term financing for the LIO and signed by Pfeffer, Hawker and Legislative Legal Services Director Doug Gardner states that the “tenant shall not consent to any termination or cancellation of the lease without lender’s prior written consent.” Rep. Sam Kito, D-Juneau, who voted to approve the Downtown Anchorage LIO purchase and penned an op-ed in his hometown newspaper the Juneau Empire justifying the decision, was the only “no” vote on the Wells Fargo purchase motion. Before the vote he stated concerns about taking action on one property while possibly being exposed to a lawsuit over the Legislature’s possible financial obligation on another. The Anchorage Downtown Partnership, a non-profit focused on generally improving the economic and livability qualities of the city’s core, sent a letter to Stevens May 2 urging the council to keep the LIO where it is because moving elsewhere would not match the city’s land use plan to have local, state and federal offices in the Downtown business district. The Midtown Wells Fargo location would put the state in conflict with local planning policies and subsequently violate state statute as well, “which directs the State of Alaska to ‘comply with local planning and zoning ordinances and other regulations in the same manner and to the same extent as other landowners,’” the letter states. The LIO is the home office for 25 Anchorage legislators and is often the de-facto meeting place for hearings when the Legislature is not in session. It substituted as the capitol building last spring when the Republican-led Legislature ignored Walker’s demand that a special session to resolve budget issues be held in Juneau. Instead, legislators “gaveled out” of the Juneau special session called by Walker and reconvened in Anchorage.  

Delegation wants repeal of regs aimed at Native contracts

Rep. Don Young is trying again to make a small change to federal code that he says will have a big impact on many Alaska Native corporations doing business with the federal government. The changes Young is seeking would repeal special criteria the federal agencies are required to consider when justifying sole-source government contracts totaling more than $20 million to Alaska Native corporations and other small businesses. That language would be replaced by existing and widely used criteria found in the 1984 Competition in Contracting Act, which Young contends is better understood and easier to apply. Young’s proposal was included as an amendment to the 2017 National Defense Authorization Act, which moved out of the House Armed Services Committee April 28. The current five-step justification process requires federal agencies to cite their authority and need to go outside the standard competitive bidding process was added to the 2010 Defense spending authorization as Section 811 of that bill. Young said in an April 29 release from his office that Section 811 has led to “major inequities” for Native contractors. “What was sold as a good governance measure in the Senate has led to the discrimination and mistreatment of Native community-owned businesses. The heightened level of scrutiny required by Section 811 is found nowhere else in the federal government, and has resulted in the net loss of jobs, more than 60 percent decline in revenue from these contracts and a frightening layer of bureaucratic red tape,” Young said. Among the regional corporations, 28.5 percent of their total revenue was from 8(a) contracting in 2014 compared to 42.9 percent in 2010. Subsidiaries of Alaska Native regional corporations and Native village corporations are often first in line for government contracts under the Small Business Administration’s 8(a) Business Development Program. The program aims to help “socially and economically disadvantaged” small business owners by allowing them to receive sole-source government contracts generally capped at $6.5 million, according to the SBA. However, agencies are allowed to award sole-source contracts of any size to Native-owned corporations. It is Young’s third attempt to clarify or repeal Section 811 since 2013. His amendments to the 2014 and 2016 Defense spending bills were pulled during negotiations with the Senate. Alaska Native Village Corporation Association Director Keja Whiteman said in a formal statement that the group supports Young’s effort to repeal Section 811. “The passage of Section 811 has been detrimental to the already heavily regulated and highly scrutinized Alaska Native corporations and Native 8(a) businesses,” Whiteman said. Sens. Lisa Murkowski and Dan Sullivan echoed Young’s sentiment in statements from their offices. “Section 811 was ‘air dropped’ in the dark of night into a non-amendable conference report to accompany the 2010 National Defense Authorization Act,” Murkowski spokeswoman Jenna Mason wrote in an email. “The full Senate was never given an opportunity to debate, amend or cast an up or down vote on the provision. This is the worst sort of process and was undertaken deliberately to silence the voice and vote of Indian Country supporters in the House and Senate.” Sullivan’s spokesman Mike Anderson noted the sole-source justification provision was implemented before he was in the Senate and said he supports language to mitigate the “harmful effects” Section 811 has had on Native 8(a) contracting opportunities. “Sen. Sullivan is committed to using his position on the Senate Armed Services Committee to attempt to correct this problem,” he wrote. Missouri Democrat Sen. Claire McCaskill has led a push in Congress in recent years to get increased oversight of Alaska Native regional corporations, particularly in regards to the companies’ business with the federal government. She argues that much of the money awarded to the corporations through the 8(a) program does not reach the corporate shareholders as intended. The 12 Alaska Native regional and smaller village corporations were established as part of the 1971 Alaska Native Claims Settlement Act. Many corporation subsidiaries have been established as small businesses to specialize in government contracting for construction, IT and operations management services among others. A comparison of Section 811 sole-source justification requirements and those in the Competition in Contracting Act by a 2012 Government Accountability Office report found the criteria to be rather similar; the biggest difference was that Section 811 requires “a determination that the use of a sole-source contract is in the best interest of the agency concerned.” The same December 2012 GAO report concluded the number of $20 million-plus 8(a) contracts issued declined after the justification requirement change because apparent confusion among agencies as to exactly when the Section 811 criteria applied. According to the report, the number of sole-source contracts to 8(a) businesses fell from an average of about 50 per year from 2008-2010 to about 20 per year after enactment of Section 811 in 2011. Another GAO report requested by McCaskill and released March 21 — titled “Alaska Native Corportions: Oversight Weaknesses Continue to Limit SBA’s Ability to Monitor Compliance with 8(a) Program Requirements” — found that 344 Alaska Native corporations and subsidiaries were still awarded roughly $4 billion in 8(a) federal contracts during the 2014 fiscal year, or nearly a quarter of the $17 billion in total government spending that went to almost 5,600 businesses in the program nationally. Of that $4 billion, about $3.1 billion went to six Alaska Native corporations and their subsidiaries according to Bloomberg’s annual list of the 200 leading federal contractors in fiscal year 2014. The six Alaska Native regional and village corporations in the top 200 were: Arctic Slope Regional Corp., No. 75 at $793 million; NANA Regional Corp., No. 85 at $707 million; Afognak Native Corp., No. 107 at $491 million; Chenega Corp., No. 119 at $441 million; Chugach Alaska Corp., No. 138 at $384 million; and Bristol Bay Native Corp., No. 142 at $363 million. Elwood Brehmer can be reached at [email protected]  

Credit legislation hearings canceled as negotiations continue

It has been three weeks since legislation to scale back Alaska’s oil and gas tax credit program took a big step backwards to the House Rules Committee. In the meantime Rules chair Rep. Craig Johnson, R-Anchorage, has put forth two very similar versions of House Bill 247 that would all but eliminate the state’s refundable credit program. However, with no committee hearings on the bill since early April, little has been heard from legislators and the public has not had an opportunity to comment on legislation changes on the issue that has constipated the entire legislative process. Majority and Minority caucus leaders in the House have said they believe a tax credit compromise could jumpstart activity on the budget and other revenue proposals, but not much more. The Rules versions of HB 247 are the fifth and sixth iterations of the legislation first introduced by Gov. Bill Walker and, compared against adaptations from other House and Senate committees, most resemble what the administration had in mind at the start of the session. What started as concessions by the Republican-led Majority to appease Minority members and a group of Republicans that have joined them in believing prior committee versions did not cut the program far enough could have swung the other way if the concessions went too far for some in the Majority to support. Walker’s plan would have raised taxes and cut the state’s annual credit obligation by upwards of $500 million per year by fiscal year 2018, according to the Revenue Department. The Rules Committee’s proposal could have nearly a $300 million per year benefit to the state — or detriment to industry — by the time it is fully implemented in 2020, the department estimates. Drastically cutting the oil and gas tax credit program that has become the state’s third largest budget line item is a foundational piece of the administration’s New Sustainable Alaska Plan to solve the $4 billion budget deficit by fiscal year 2019. Regardless of the prospective savings from cutting the industry incentive program, the state is still expected to owe about $775 million during fiscal 2017 for credits currently being earned by companies. The operating budgets passed by the House and Senate currently fund just a fraction of that obligation, meaning hundreds of millions of dollars more will have to be added to the final budget whenever the credit stalemate is resolved. Alaska Oil and Gas Association CEO Kara Moriarty said in an interview her trade association has answered questions from legislators that have asked for feedback on the latest bills and that she is just waiting to testify whenever the next committee hearing on HB 247 might be. The industry has pushed back against changes to the program at a time when oil prices are at best near the current cost to produce a barrel of North Slope crude — about $46 per barrel, according to the Revenue Department. Moriarty said the numerous changes to oil tax policy, whether supported or opposed by the industry, have at least been rooted in a principle with an ultimate goal in mind, which is missing this time. “(Lawmakers) are trying to set a policy to fill a budget gap and for us, we’re just waiting,” she said. Increasing taxes when companies are already laying off significant chunks of their workforce will do little more than lead to decreased oil and gas production in the state, industry representatives continue to emphasize. The administration and legislators pushing for the changes need to ask, “What do you want Alaska to look like five years from now, 10 years from now?” Moriarty said. “It’s not a political issue for us. Whatever the policy is, we will make an economic decision.” Released May 2, the latest Rules HB 247 would close the Cook Inlet credit program to new entrants at the end of 2016. Companies with oil and gas production in the Inlet basin during 2016 would still be eligible for fading capital expenditure credits that would be terminated at the end of 2018. State subsidies for natural gas exploration and development in the Inlet have largely been credited with securing Southcentral’s energy supply in recent years. Leaders of several of the region’s utilities Credits for exploration in “Middle Earth” Alaska— areas of the state other than Cook Inlet or the North Slope — would be maintained. The North Slope refundable Net Operating Loss credit would also terminate at the end of 2016 for all companies except the smallest producers. Companies with less than 20,000 barrels per day of production could continue to receive the 35 percent NOL credit through 2019. Ending the refundable NOL credit would push companies to deduct annual operating losses from future tax liabilities, thus establishing a true tax “floor” by not allowing deductions to reduce a company’s tax obligation below the 4 percent minimum production tax. The Department of Revenue estimates a 4 percent minimum production tax could raise $100 million or more per year in tax revenue once the NOL is fully eliminated. Legislators on both sides of the debate have conceded the impact of refundable NOL credits on the minimum tax during low oil price periods — such as now — was not considered while the industry-supported oil tax reform known as Senate Bill 21 was vetted and passed in 2013. At that time oil prices were consistently near $100 per barrel. Elwood Brehmer can be reached at [email protected]

MEA inks deal with Hilcorp for flat rate, opt out

Matanuska Electric Association’s latest natural gas supply contract has two unique characteristics designed to benefit the utility. The contract with Hilcorp Energy, the dominant producer in Cook Inlet, is for all of MEA’s projected gas demand from April 2018 through March 2023. At an estimated annual demand of a little more than 6 billion cubic feet, or bcf, of gas per year, the contract covers about 32 bcf of gas sales over the five-year term. It was submitted to the Regulatory Commission of Alaska April 19 and is a tentative deal pending the commission’s approval. MEA General Manager Tony Izzo highlighted in an interview that the $7.55 per thousand cubic feet, or mcf, of gas price not only should save the co-op utility’s members $3 million in the first year, but also that the price is consistent regardless of how much gas MEA needs on a given day. “What I’m excited about in this contract is I pay $7.55 for everything. I have no swing gas premium,” Izzo said. “Our customers will pay that price for the lowest demand day and the highest demand day.” It has basically been standard practice for recent Cook Inlet gas supply contracts to include a base load price for the majority of a utility’s demand. Additional gas needed mostly during cold weather and dark winter months is then sold at a premium price that can be as much as 50 percent higher than the base load price for emergency, or needle peak, supply. Hilcorp Energy declined to comment on the terms of the gas supply contract with MEA. Enstar Natural Gas Co., the region’s largest natural gas buyer, agreed to a contract in February through early 2023 with Hilcorp for a first year weighted average price of $7.56, which includes premium sales. That deal will save Enstar customers $14 million in the first year of the contract. Izzo said MEA’s deal provides price certainty to its customers who won’t see feedstock fuel prices go up at the same time they are using more electricity. The cost savings are the result of a price drop from the $8.03 per mcf base load price MEA and most Cook Inlet gas customers will be paying under contracts with prices set by the 2012 Consent Decree that expires at the end of 2017. The Consent Decree deal was reached by the Attorney General’s office and Hilcorp and capped Inlet gas prices through 2017, thus allowing Hilcorp to purchase gas and oil interests from Marathon and Chevron and become the majority gas supplier in the basin in late 2012. MEA and Hilcorp agreed to a 2 percent annual price escalator after the first year $7.55 per mcf price. The Consent Decree allows for a 4 percent annual price increase. The deal also gives MEA a partial “out clause” that it can exercise on up to 20 percent of its gas demand. “For about 20 percent of my supply, if the market changes and hopefully (another producer adds supply) and the price is attractive I can notify Hilcorp at any time before or during this contract and say, ‘I’m going to exercise the turndown option,’” Izzo said. However, he noted the price from a new supplier would have to be substantially less than the current contract price because Hilcorp has the right to add 25 cents per mcf to MEA’s remaining contracted demand if the turndown option is used. Similar to what Enstar officials said when their contract went to the RCA in February, Izzo said the five-year term is a compromise between supply security and encouraging diversity among producers. He thanked Hilcorp for its work to increase gas supply from mature Inlet fields and noted that just a few years ago utilities couldn’t any contracts for longer than two years. The leaders of both utilities said Hilcorp was willing to agree to longer-term contracts. “I’m real happy with the price but at the same time I really want the market to grow; I want to have an alternative supplier; I want to diversify the portfolio and I want to see prices go down so how do I do that?” Izzo surmised. “I stick with a five-year term. It’s not forever but I was able to get this turndown option and hopefully one of these (other producers) will get some cash flow off that.” Elwood Brehmer can be reached at [email protected]  

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

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]

Tax credit rewrite hits fifth iteration amid impasse

Make that five distinct versions of oil and gas tax credit legislation this session. The House Rules Committee took its swing at hitting the “sweet spot” on a tax credit bill when Rules chair Rep. Craig Johnson, R-Anchorage, released the latest iteration of House Bill 247 on April 26, day 99 of the 90-day session. The Rules bill makes the most drastic cuts to the credit program of the various legislation introduced in committees. It could save and generate up to $365 million annually by fiscal year 2021, according to a Department of Revenue analysis. That is second only to the original bill put forward by Gov. Bill Walker’s administration, which is projected to improve the state’s balance sheet by about $500 million at most. Milder committee versions of credit revisions put forth in the House and Senate would cut $50 million to $150 million from the program after several years of phased reductions. Regardless of prospective savings, Johnson and administration officials have noted the state is still on the hook in fiscal 2017 for about $775 million in refundable credits companies are expected to earn prior to any program changes taking effect. The vast majority of that sum also still needs to be added to the operating budget. An impasse between the Majority and Minority caucuses in the House centered on the tax credit overhaul has essentially stalled all other important work in the Legislature, even in the Senate where that Majority holds 16 of 20 votes. Without an amenable credit bill, the Democrat-led Minority will not approve a draw from the Constitutional Budget Reserve savings account, which requires a three-quarters vote from both chambers of the Legislature, needed to pay for the fiscal year 2017 budget. Visible progress on the budget and this session’s biggest single project —establishing a sustainable budget draw from the Permanent Fund Earnings Reserve account — has slowed as well. Minority members have stressed that the state should not continue to pay upwards of $700 million per year to the oil industry while significantly cutting education and rural assistance programs to shrink a $4 billion deficit. They have gained support from some Republicans as well, notably Homer Republican Rep. Paul Seaton, who is leading a caucus of Majority members bucking the leadership. More conservative — at least in regards to this issue — Republicans have noted that any money the state still has to spend is thanks to the oil industry, which historically has funded nearly 90 percent of the state’s budget. Seaton mostly sided with Minority Democrats when amendments to the House Resources version of HB 247 were considered. He also led the push to oppose a Finance Committee version HB 247 on the House floor earlier in April. Enough House Majority members didn’t think the bill that reached the floor cut the program far enough that the bill would not have passed. House Speaker Rep. Mike Chenault then moved the bill to the Rules Committee for another try. House leaders on both sides have said an oil and gas tax credit compromise could trigger quick action on those remaining bills needed to finish the session. Industry representatives from companies and trade associations insist any change to the state’s tax credit system or underlying tax structure will hurt production and increase job losses in the industry at a time when the average cost of production and transport for North Slope oil — about $46 per barrel, according to the Department of Revenue — exceeds market prices. The Labor Department estimates Alaska has lost about 1,800 oil and gas industry jobs over the past year. Walker said at an April 27 press briefing that he met with the Slope majors on April 25 to discuss the issues each side has with the proposed changes. The administration has also met with independent companies to find ways to incentivize their growth while reducing the expense to the state throughout the process, he said. “We’re in some big changes as far as what we can and can’t do, and what was business as usual not that many years ago is going to be very difficult this year,” Walker said. “We’re looking very closely at how to advance and make (tax credit) changes with a minimal impact, but we know there will be impact across the board with all companies.” Statewide, the Rules Committee version of HB 247 would annually cap the credits each company is eligible to receive at $85 million, on par with limits proposed in House Finance and Senate Resources committees. It would also end the transfer or sale of credits to companies with a production tax liability. Transferring credits between companies without production tax liabilities, namely small producers and explorers, would still be allowed. The Rules version is also the first since the administration’s to make public the companies getting refundable credits and how much they receive each year. Industry has railed against a more transparent credit program contending it could quickly devolve into disclosing confidential tax information that might even violate federal law. Minority legislators rebut that the state does not require companies to accept the credits they are eligible for; therefore allowing companies to choose if they want to take the incentives and subsequently disclose some information. Cook Inlet The Rules Committee took the ramping down of Cook Inlet capital expenditure credits in other committees a step further and eliminated them entirely by calendar year 2019. In the interim, only companies with oil or natural gas production from the Inlet basin by the end of 2016 would be eligible for the slowly vaporizing credits. Tied to that is language in the bill calling for a new Inlet oil and gas tax regime, and possible credit program, to be implemented by January 2019. Legislators have discussed the need to reexamine Cook Inlet oil and gas taxes in several years throughout the credit debate. While they do pay the state’s 12.5 percent royalty share, Inlet producers pay no oil production tax and a minimal production tax on natural gas. However, Inlet production is largely viewed as a means to a secure energy supply for Southcentral and not as revenue stream for the state. Oil production is about 17,300 barrels per day in Cook Inlet. The latest HB 247 would also eliminate the Cook Inlet Net Operating Loss credit at the end of 2017. North Slope There are two major changes for companies on the Slope pertaining to the Net Operating Loss, or NOL, credit and the Gross Value Reduction credit for “new oil.” The Rules Committee eliminated the 35 percent NOL credit right away at the end of 2016 for large producers and explorers. Small producers pulling less than 20,000 barrels per day would get the NOL credit through 2019. At that point the refundable NOL credit would shift to a more traditional deduction against future tax production tax liability. Changing the NOL credit to a deduction would truly “harden” the 4 percent production tax floor because deductions can take a liability to, but not through, the minimum tax like the refundable credit could. Legislators and their tax consultants have said Senate Bill 21 was intended to have a minimum 4 percent production tax, but oil prices low enough to allow NOL credits to pierce the floor were not even considered during the SB 21 debate of 2013. The administration’s proposal hardened the floor, but also raised it to 5 percent. House Finance reset the production tax floor at 2 percent. The other versions from the House and Senate Resources committees did not address the minimum tax for fears that hardening the floor would increase net operating loss obligations in future years. Revenue Commissioner Randy Hoffbeck said April 27 that there are concerns about how the Rules Committee addressed the NOL — that it would allow large producers to eventually deduct losses at low price points but leave explorers to absorb their full losses until they have production. Shifting the NOL to a simple tax deduction would also seemingly quell some of the fears about publicly reporting what companies are getting refundable tax credits. With the NOL credit as a refundable credit, it would be fairly simple to calculate a company’s yearly performance if its application of a 35 percent NOL credit is made public. Pulling the NOL from the list of refundable credits closes that avenue; a company’s deductions remain confidential. The 20 percent Gross Value Reduction for oil produced from new development would also sunset after 10 years of production. Currently, there is no statute of limitations on the GVR for new oil. Elwood Brehmer can be reached at [email protected]

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