Source: BOE Report
Police Scotland confirmed tonight that it had submitted a report to the Procurator Fiscal over concerns of criminality relating to the breach of the 500 meter exclusion zone designed to protect the Transocean installation, the Paul B Loyd Jnr.
Police Scotland are seeking to make further arrests as it attempts to bring to an end the bitter North Sea standoff between BP and the climate activist group Greenpeace.
Greenpeace have successfully halted the BP-contracted drilling rig from reaching the Vorlich field on several occasions over the last three days, using the Greenpeace vessel the Artic Sunrise vessel to block its path.
One Greenpeace protestor even entred the water to swim into the path of the Paul B Loyd Jnr earlier today. Greenpeace posted a picture to its Twitter feed of the stunt.
Greenpeace said it had “used every possible peaceful means to stop BP drilling for more oil”.
On Sunday, Oil and Gas People reported how a Greenpeace Rib was chased out of Aberdeen harbour as it attempted to enter without permission. The craft was launched from the Greenpeace ship Artic Sunrise and made several attempts to enter the harbour with the port authority vessel blocking its path. View the video here
Police have already made a series of arrests over perceived criminal acts by Greenpeace in the 11 day standoff.
Police Scotland said the latest attempt to bring arrests was in connection to alleged offences under the Petroleum Act 1987 following an incident near to the rig on the morning of Sunday 16 June 2019.
OGUK described Greenpeace behaviour as “dangerous” and “wholly unacceptable”.
OGUK communications director Gareth Wynn said: “What we need now is sensible and pragmatic discussion with government, other industries and wider society about how we will do it and to make the informed choices that are needed.
“Prematurely shutting down production from the North Sea only increases our reliance on imports.”
A spokeswoman for the UK Department for Business, Energy and Industrial Strategy said: “We are monitoring the situation and are in daily contact with BP and the Scottish Government.
“We are confident that Police Scotland are examining all options to bring the protest to a safe end.”
OGUK described Greenpeace behaviour as “dangerous” and “wholly unacceptable”.
Scottish Energy Minister Paul Wheelhouse said the Scottish Government was “keeping a watchful eye” on developments
Here’s another reason for Presidents Donald Trump and Xi Jinping to seal a swift trade deal: it could put the U.S. on track to become China’s biggest supplier of liquefied natural gas, according to Morgan Stanley.
A pact this year between the world’s two largest economies -- the bank’s base case -- will likely lead to large Chinese purchases of American LNG, which would help shrink the U.S. trade deficit, it said in a report. This may help boost the U.S. share of China’s gas imports by 2025 to 21%, compared with 5% without a deal, Morgan Stanley said. It was only 2% last year.
“A higher LNG trade from the U.S. to China would potentially be a win-win deal for both,” analysts including Andy Meng wrote. Not only could it reduce the U.S. trade deficit with China by $17 billion annually, it may also help China save $1.8 billion a year in energy costs, the bank estimates.
There may also be major implications for the global LNG market. The U.S. is bringing on new projects and is set to become the No. 1 supplier. All that production needs to find a home, and China is expected to take the title as top importer some time early next decade. Without a deal, it’s likely to turn to other countries including Russia, Australia and the Middle East to fulfill its gas demand, Morgan Stanley said.
China’s imports of American gas have dropped since Beijing slapped a 10% duty on the fuel in September in a series of tit-for-tat tariffs. Pressure has mounted after the duty was raised to 25% from June as a deal remained elusive. Trump is seeking a meeting with Xi at the upcoming Group of 20 summit in Japan, threatening to raise tariffs on China again if it doesn’t happen.
A “no deal” scenario would be negative for long-term U.S. natural gas prices, as well as for projects seeking final investment decisions. The ongoing trade war has caused Chinese buyers to avoid investing in U.S. developments or signing long-term offtake agreements.
It would also push China to buy more gas from existing suppliers, with Russia’s Gazprom PJSC and Woodside Petroleum Ltd. in Australia seen as key beneficiaries. While there is still sufficient supply under this scenario, the cost of imports would likely be higher than U.S. LNG, the bank said.
Please leave comments and feedback belowhello
Source: BOE Report
Source: BOE Report
Source: BOE Report
Source: BOE Report
Source: BOE Report
What’s Hot, What’s Not
As Wall Street has slammed the brakes on providing funding via secondary equity offerings and public bond raises, E&Ps are increasingly switching lanes towards other strong market segments as opportune sources of capital. This article provides data and insight on the depth of the Wall Street shutdown (The Market Taketh) as well as some sweet spots for U.S. E&P operators and capital providers to tap into for opportunities (The Market Giveth) including a strong Royalty and Minerals market, a strong Midstream market and other bright spots.
From an industry, capital allocator and investors perspective, the suite of product offerings by Drillinginfo, including its Market Research, Market Intelligence, Mineral and Midstream Research offerings allow for dynamic, single-sourced, integrated quality data sets to stay ahead of the pack and quickly identify profitable opportunities in the one of largest markets in the world (energy) across the entire the energy value chain — be it above ground or below ground, across commodities, in the U.S. or international, or in the public or private markets.
The Market Taketh
Now that we are approaching the mid-year point of 2019, it is remarkable that year-to-date no U.S. operator has raised a single dollar from an equity follow-on issuance.
In fact, the last issuance occurred back on November 19, 2018 when Contango Oil & Gas raised net proceeds of $33 million via issuance of 8.6 million common shares at $4.00/share to support its southern Delaware Basin Bullseye and NE Bullseye development in Pecos County.
This blowback from Wall Street stands in stark contrast to the run and go days for investors backing U.S. public E&P land grabs during 2016 and early 2017.
From Q2 2016 through Q1 2017, equity investors were eager to back acquisitions which totaled $90 billion, of which nearly 60% or $53 billion was for land (aka drilling inventory). In 2016 alone, Wall Street investors wrote $30 billion in equity checks to the acquirors, often overnight. At the time, the open-door policy of Wall Street enabled transformative acquisitions by U.S. operators that set the stage for decades of drilling.
In a twist of irony, soon after the land grab, which by default requires enormous piles of money to drill out the inventory, Wall Street slammed the bank shut and demanded companies develop those inventories through cash flow – significantly slowing the pace of growth. To put numbers around this, at mid-2018 our data indicates that operators publicly disclosed (in their own language) buying net 50,261 drilling locations from January 1, 2016 through June 30, 2018 which would require nearly $350 billion (by Drillinginfo cost estimates) in drilling and completion capital to drill out. That’s a lot to develop out of “cash flow”!
To be sure, the shut down of easy equity has slowed the pace of U.S. resource play inventory development — which is of such scale that going full throttle would certainly have increased the global supply/demand balance and pressured oil prices more than they already are.
In the past decade, annual bond raises by U.S. operators average around $30 billion. Since January 2015, U.S. operators have issued $107 billion in bonds, compared to $60 billion in equity.
Largely as a result of the equity market shutdown, the bond markets have followed suit as most companies are challenged to raise additional debt without a concomitant increase in equity. The few bonds that are getting through are largely refinances to extend maturities.
Nearing mid-year 2019, U.S. E&P operators have raised a paltry $3.2 billion in bonds thus far this year from just seven companies –
- Apache, June 5 ($394 MM net, Unsecured Notes due 2049, 5.35% coupon)
- Apache, June 5 ($596 MM net, Unsecured Notes due 2030, 4.25% coupon)
- Goodrich, May 31 ($11.8 MM net, Secured Second Lien due 2020, 13.5% coupon)
- Kosmos, April 4 ($637 MM net, Senior Notes due 2026, 7.125% coupon)
- CNX Resources, March 14 ($490 MM net, Senior Notes due 2027, 7.25% coupon)
- Centennial Resource, March 12 ($490 MM net, Senior Unsecured Notes due 2027, 6.875% coupon)
- Cimarex, March 7 ($497 MM net, Unsecured Notes due 2029, 4.375% coupon)
- PetroQuest, February 8 ($78 MM net Secured Second Lien due 2021, 10% coupon)
The Market Giveth – What’s Hot
While public investors have gone on strike funding E&P operators, one sector is gaining momentum as an alternative way to play the development of the U.S. resource plays. The mineral and royalty market set a record $3.3 billion in M&A activity in 2018.
Not only is this market active in M&A, the public markets are also pumping fresh capital into this market with the latest example being the IPO of Brigham Minerals (NYSE: MNRL, $1.0 billion market cap) which went public on April 18, 2019 via an upsized offering of 14.5 million shares priced at $18 and currently is trading north of $20. Other pure-play publicly-traded mineral and royalty companies (as of June 17) include –
- Viper Energy Partners (NASDAQ: VENOM, $3.8B market cap, IPO June 2014)
- Black Stone Minerals (NYSE: BSM, $3.2 B market cap, IPO April 2015)
- Kimbell Royalty (NYSE, KRP, $1.1 B market cap, IPO Feb. 2017)
- Falcon Minerals (NADAQ: FLMN, $0.6 B market cap, formed August 2018)
- Dorchester Minerals (NASDAQ: DMLP, $0.6 B market cap, formed 2003)
The Grandaddy included in this sector is Texas Pacific Land Trust (NYSE: TPL), an entity created in 1888 via a reorg of the Texas and Pacific Railway that ultimately created the Trust. TPL is now one of the largest landowners in Texas holding 888,333 surface acres and 459,200 acres with a perpetual oil and gas royalty interest, much of which is in the Permian Basin. Prior to the onset of the US shale plays, this stock traded around $30/unit at the beginning of 2010. From January 1, 2010 to April 8, 2019, the stock soared to a recent peak of $901/unit. The units currently trade at ~ $715/unit and the Trust sports a market cap of $5.5 billion.
For U.S. E&P operators, a thriving mineral and royalty markets represent an opportunity to raise capital via the sale of outright minerals or carved-out royalties from high net revenue interest assets. Examples include Range Resources raising $300 million via a 1% ORRI carve out sold to Ontario Retirement Teachers Pension Plan, Continental Resources selling some Oklahoma minerals ($220 million) and forming a JV with Canada’s leading gold-focused royalty company, Franco-Nevada, and of course Diamondback Energy’s dropdowns to its affiliated company, Viper Energy. The attractiveness of this increasingly transparent market also drove Chevron to organize its U.S. minerals into an internal division so that it can retain move towards realizing the full value of these minerals which look to be undervalued under the Chevron company.
From 2015 through 2018, the U.S. Midstream deal market averaged ~$113 billion per year as buyers vie to capture the value from the growing midstream buildout to support surging production from the resource plays. In 2018, this activity reached a modern peak at $170 billion with U.S. E&P operators also participating with record $12 billion of sales into this market.
Recent, notable deals by U.S. E&P operators include the remaining sale of Anadarko’s ownership in Western Gas Partners for $4.0 billion in November 2018. In August 2019, Oxy sold non-core assets to privately held Lotus Midstream and Modus Midstream $2.6 billion. That same month, Apache sold 71% of its Alpine High midstream assets in the Delaware Basin for $2.5 billion. Earlier in the year, Gulfport and EQT sold Ohio gathering assets to EQT Midstream for $1.5 billion. Mid-cap E&Ps like Oasis Petroleum, PDC and Matador have also tapped into this market as avenues to raise additional capital outside of traditional sources.
Not to be discounted, the pivot of private equity into the midstream sector is alive and well. Since 2015, we’ve tallied over $24 billion in PE commitments to midstream companies and projects. 2018 was a record year with $9.2 billion committed (compared to $5.3 billion in the upstream sector) with 2019 thus far tallying over $3.4 billion.
Aside from backing new companies, private equity is directly investing in deals themselves. Since 2015 private equity and financiers bought about 6% of the $600 billion in U.S. midstream deals. However, the role of this sector on the buyside is surging and on a record pace YTD accounting for over 40% of this year’s $29 billion in U.S. midstream deals. Two strong examples include Stonepeak Infrastructure Partners $3.6 billion buy of Oryx Midstream and a Blackstone Infrastructure led group to invest $4.8 billion into a controlling stake in Tallgrass Energy, LP. In announcing the deal, management emphasized that the fund is an open-ended fund that is “very long-tailed” and capable of financing the $4 – $5 billion of capital projects on deck at Tallgrass.
As the public markets tighten their grip on financing upstream activities, we certainly expect E&P companies to look towards selling or forming joint ventures regarding midstream assets as the buyer universe looks to be hungry to expand. A case in point is Noble Energy who in April 2019 disclosed that with the assistance of its advisors, the company is conducting a review of strategic alternatives regarding its effective 45% ownership in Noble Midstream Partners.
Fundamentally, the landscape for private equity investors in the upstream sector is changing. In recent history, there are great success stories of PE sponsors backing talented teams for new private E&Ps with a playbook to go acquire lands early, deploy the latest technology and operational best practices with an objective to de-risk the lands for a sustainable, consistent drill and develop program. The poster child of this model is the Delaware Basin where PE-backed companies deployed risk dollars and were able to exit to a public company seeking to put a solid footprint in the emerging basin. The funding by the buyers was often supported by the public equity markets with funding secured in overnight raises.
As the table below depicts, since 2015 PE-sponsors have committed over $44 billion of which roughly 11% has turned. The Permian is the largest destination representing nearly 50% of those risk dollars. PE investments recently peaked in 2017 at nearly $14 billion.
PE investments dramatically slowed in 2018 to just a little over a third of the prior and in 2019 has only tracked $1.6 billion.
While new upstream commitments have slowed, the landscape of PE investments does offer opportunity on multiple fronts. Traditionally, PE model looks to exit within 3 to 7 years so there is a host of companies that are nearing the exit timeframe and certainly present buying opportunities. It is fair to say currently, the market favors buyers who have many choices of where to deploy acquisition capital.
Also, for those looking to deploy fresh private equity, the aforementioned Wall Street negative sentiment regarding equity and bond issuances sets up alternative models. Instead of the buy, de-risk, sell model, some PE backed companies are looking to build full scale E&P companies and drill out their de-risked positions. At the well level, even in today’s price environment there are attractive IRRs that PE backed companies can achieve – given access to additional drilling and completion capital. This capital may take the form of direct equity or alternative structures including non-op commitments, drillco commitments or joint ventures.
For those who look long term, there is also an opportunity in this market to deploy capital towards PDP production valued at current commodity prices. The lagniappe pie associated with PDP buys is increasing as the public markets continue to change the valuation metrics for public E&Ps.
Much has been written regarding the Drillco model. In short, the structure provides for a win/win between a capital provider seeking to invest in low risk wells and an E&P company seeking to accelerate the development of long-dated inventory. An example of the structure is shown to the right.
In simple terms, the operator wins once the capital provider achieves a certain rate of return via a flip of the share of the cash flow generally after the peak production from the well. The capital provider wins by achieving minimum required rates of returns and is rewarded with a tail of cash flow through the life of the well.
Given that many E&P companies have decades worth of de-risked inventory and limited capital sources, Drillco’s are an attractive model to supplement basic capital programs with additional drilling and cash flow.
The types of capital providers reach from typical PE firms to capital firms targeted directly to the Drillco structure.
In the current capital environment, Drillco’s present an excellent opportunity for both private capital and E&P operators (public or private). The key to success for the capital provider is technical due diligence of the geology and economics of a drilling program plus the operator’s ability to perform. For operators, there are choices of capital partners.
Keys to Success
The Drillinginfo platform has grown exponentially over its 20-year history. All the data in this article are sourced solely from our platforms. We provide the industry’s leading dynamic datasets that are easily accessible to both the industry and capital providers to find the best partners or deal opportunities. No longer are players left in the dark. The data talks and the opportunities for wealth creation, particularly in today’s environment, are numerous. If you haven’t checked in lately, we encourage you to call us for a full demo of the power of Drillinginfo.
Also, check out the prior articles I’ve written under this series:
- Rising Above the Fray Series – Tracking the Horserace for the Anadarko Petroleum Prize
- Rising Above the Fray Series
For information regarding Drillinginfo products, click here.
The post Rising Above the Fray Series – The Market Taketh and The Market Giveth appeared first on Drillinginfo.
Underlying the one-year anniversary in mid-August of the signing of the ‘Convention on the Legal Status of the Caspian Sea’ is one of the greatest oil industry swindles in recent years. When representatives of the five Caspian littoral states meet on the 11th and 12th of August, Iran intends to seek some redress from Russia on Moscow’s manoeuvring last August. The Islamic Republic believes that it was robbed of its historical rights in the Caspian, conned out of a US$50 billion per year income, and left without Russia’s support against the re-imposition of U.S. sanctions.
Little of any apparent consequence was decided last August when the five Caspian littoral states – Russia, Iran, Kazakhstan, Turkmenistan, and Azerbaijan – signed the ‘Convention on the Legal Status of the Caspian Sea’. The limited publicity that surrounded the signing stated only that the agreement stipulated that relations between the littoral states would be based on the broad principles of national sovereignty, territorial integrity, equality among members, and the non-use of threat of force.
It refrained from specifically going into details about share allocations in the Caspian Sea resource and talked only vaguely about giving the area ‘a special legal status’. However, a senior oil and gas industry source who works closely with Iran’s Petroleum Ministry told OilPrice.com that there was a secret second part to the deal that has proven explosive for the perennially fractious relations between the Caspian states.
At stake is the massive Caspian Sea hydrocarbons resources prize that has been fought over since the dissolution of the USSR in 1991 resulted in three additional partners – Kazakhstan, Turkmenistan, and Azerbaijan - to the original partnership of Russia and Iran. Prior to the fracturing of the USSR into its constituent independent states, Iran and the USSR had struck the original agreement in 1921 to split all ‘fishing rights’ in the Caspian area 50-50. This was amended in 1924 to include ‘any and all resources recovered’, meaning in practical terms that all hydrocarbons resources would be shared equally between Russia and Iran. “Iran should have said back then that Russia should have shared its Caspian stake with the three former USSR states, but it [Iran] was content to wait for the official legal dispute to be settled,” underlined the Iran source.
At stake is the allocation of revenues from the wider Caspian basins area, including both onshore and offshore fields, that is conservatively estimated to have around 48 billion barrels of oil and 292 trillion cubic feet (Tcf) of natural gas in proved and probable reserves. Around 41 percent of total Caspian crude oil and lease condensate and 36 percent of natural gas exists in the offshore fields, with an additional 35 percent of oil and 45 percent of gas estimated to lie onshore within 100 miles of the coast, particularly in Russia’s North Caucasus region.
The remaining 12 billion barrels of oil and 56 Tcf of natural gas are believed to be variously located further onshore in the large Caspian Sea basins, mostly in Azerbaijan, Kazakhstan, and Turkmenistan. The area accounts for an average of 17 percent of the total oil production of the five littoral states that share its resources, on average totalling 2.5-2.9 million barrels per day (mbpd).
Before the ‘Convention on the Legal Status of the Caspian Sea’ agreement was signed last August, oil output targets for each country were set three months in advance, with all revenues paid into a central Caspian oil account, which was then split in equal proportions of 20 percent between the five littoral states, said the Iran source. The revenues, at least prior to the re-imposition of sanctions against Iran by the U.S. late last year, usually comprised 95 percent U.S. dollars and Euros, but with some local currencies in the mix.
Against this backdrop, the legal designation of the Caspian as either a ‘sea’ or a ‘lake’ would have far-reaching repercussions on the assignment of revenues from it. If it was designated a sea then coastal countries would apply the ‘United Nations Convention on the Law of the Sea’ (1982), in which event each littoral state would receive a territorial sea up to 12 nautical miles, an exclusive economic zone up to nautical 200 miles, and a continental shelf. In practice, this would mean that countries such as Turkmenistan and Azerbaijan would have exclusive access to offshore assets that Iran would not be able to access.
If it was designated a lake – and this was the informal designation before the August agreement – then the countries could use the international law concerning border lakes to set boundaries, by which each country effectively possesses 20 percent of the sea floor and surface of the Caspian.
In the preparations for the signing of the ‘Convention on the Legal Status of the Caspian Sea’ last August, Iran had engaged lawyers to challenge the established 20 percent share that each littoral state had informally agreed upon, based on the fact that Russia should have used its own original 50 percent share to make good stakes for its former USSR states.
Iran was confident at that point that Russia would show some flexibility as, after the U.S. pulled out of the nuclear deal last May, Moscow immediately made a deal with Iran that would effectively have given it control of all of Iran’s oil and gas resources. Specifically, the deal was that Russia would hand Iran US$50 billion every year for at least five years. This would cover all of Iran’s estimated US$150 billion of costs to bring all of its key oil and gas fields up to Western standard, with US$100 billion left over for the build-out of other key sectors of its economy.
“Russia also pledged to veto all attempts in the United Nations Security Council [UNSC] to have sanctions against Iran increased or to have the terms of the original nuclear deal re-drawn to include further sanctionable actions such as missile testing or not allowing snap inspections of all military facilities, which it could do as it is as one of just five Permanent Members on the UNSC,” said the Iran source.
In exchange for this, Iran, in addition to giving Russia preference in the oil and gas sector, was also to tighten its military co-operation with Russia, including buying Russia’s S-400 missile defence system, allowing Russia to expand its number of listening posts in Iran and doubling the number of senior ranking Islamic Revolutionary Guards Corps (IRGC) officers that are seconded in Moscow for ongoing training, to between 120 and 130.
The catch for Iran was that, under the terms of the agreement, there was no clause that allowed Iran to impose any penalties on any Russian developer firm for slow progress on any field for the next 10 years. The Russians, though, during this entire 10-year period, would still have the right to dictate exactly how much oil was produced from each field, when it was sold, to whom it was sold, and for how much it was sold. Russia also had the right to be able to buy all of the oil – or gas – being produced from fields that their companies were supposedly developing at 55-72 percent of its open market value for the next 10 years.
“The Iranians naively thought this meant that they had entered into a genuine two-way partnership with Russia but Russia didn’t see it that way,” the Iran source said. “In the Russian way of seeing things, once it had secured Iran in this deal, effectively making it a client state, it had no reason to honour any other of its previous obligations,” he added. “The situation was also worsened for Iran by the fact that Russia had its own problems with U.S. sanctions and didn’t want to make things worse by siding so thoroughly with Iran,” he highlighted.
Given these considerations, and the fact that Russia wanted to strengthen its relations with the previous USSR states, Moscow was the prime mover in having the Caspian designated as a sea, not a lake. This was on the basis that because Russia had opened up the channel from the Volga River into the Caspian to prevent the levels dropping, the Caspian no longer conformed to the legal definition of a lake, which is that it is a localised water deposit standing independent of any river that serves to feed it.
“This meant, effectively, that Russia could divide up the shares as it saw fit, and the way it saw fit was to benefit its existing ally, Kazakhstan, which was assigned a 28.9 percent share, and its wished-for ally, Azerbaijan, which secured a 21 percent stake, while Russia saw a slight increase, to 21 percent, while Turkmenistan’s share goes down to 17.225 percent, as it is seen as a softer touch by Russia, and Iran’s share goes down to just 11.875 percent,” said the Iran source. “This switch from 50 percent to just over 11 percent means that Iran will lose at least US$3.2 trillion in revenues from the disputed and lost value of energy products going forward,” concluded the Iran source.
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Source: BOE Report
Shell Australia has retained CHC Helicopter as the provider of helicopter transportation services to the giant Prelude FLNG facility offshore Australia.
“The new agreement continues CHC’s six-year relationship with Shell in this monumental project development,” CHC said on Tuesday.
Under the agreement, CHC will provide Sikorsky S-92 helicopters and crews for daily passenger transport and emergency flights between the Broome base and the Shell Prelude project, which is located approximately 475km north-north-east of Broome in Western Australia’s Kimberley region.
Refueling between Broome International Airport and Prelude will take place at Djarindjin Airport, which is owned and operated by the local Djarindjin Aboriginal Community.
Shell last week sent the first shipment of liquefied natural gas (LNG) from the 488-meter-long and 74-meter-wide floating facility, dubbed the largest floating facility ever built.
Commenting on the Shell contract CHC Regional Director for the Asia Pacific Vince D’Rozario said: “We are humbled that Shell has once again chosen CHC to be its partner as Prelude moves into the critical production phase,”
He said that during the past six years, CHC has transported more than 50,000 passengers, and accrued over 10,000 flight hours.
CHC did not provide details regarding the contract value and length.
Mainstream environmental groups are working alongside Colorado’s oil and natural gas industry to turn the sweeping regulatory overhaul known as SB 181 into an effective, efficient workable law. But the extensive rulemaking process is being impeded by fringe “Keep It In the Ground” activists set on banning all oil and natural gas development in the state.
Those differences of opinion have been made crystal clear at the Colorado Oil & Gas Conservation Commission (COGCC) meetings, in local communities throughout the state, and via verbal barbs in the media.
Activists Groups Didn’t Support Passage of SB 181
When SB 181 was passed by a Democratic-controlled state legislature and signed by Colorado Gov. Jared Polis in April, it had the support of Conservation Colorado and other mainstream environmental groups., Noticeably silent from the discussion were fringe KIITG activists who claimed the legislation didn’t go far enough. With the legislation becoming law, and all signs pointing to a willingness by multiple, diverse parties to work together to give clear direction to what it will entail, Polis declared the oil the gas wars were “over.”
But activist groups including Colorado Rising, 350 Colorado, and Be the Change, who never supported the bill in the first place, are now using it as a mechanism to call for a statewide moratorium on all new oil and natural gas production until the rulemaking process concludes in likely another two years.
Those requests were soundly rejected by the COGCC when Director Jeff Robbins said that a moratorium was “contrary to the intent” of SB 181. However, local communities, newly empowered by the law, have enacted their own moratoria.
Activists Attack COGCC and Polis
Since the COGCC’s declaration that there would be no state moratorium, activist groups have only pushed harder, and have accused the COGCC of undermining the intent of the law.
Joe Salazar, the executive director of Colorado Rising told the Colorado Sun:
“This is an utter disappointment. Legislators were thoughtful in drafting Senate Bill 181, and for them to find out the COGCC has screwed it up as monumentally as it has is going to be a disappointment to them.”
Similarly, Joel Dyer, an editor at Boulder Weekly, wrote a scathing column directed at elected officials who he feels aren’t doing enough:
“As our governor knows all too well, this is not the first time he has declared a truce with the oil and gas industry on our behalf without our permission or support. … The oil and gas war may indeed be over for these professional compromisers, but it’s not because the war was won. It’s because they chose to surrender.”
During public hearings this week at the COGCC, representatives from Colorado Rising, 350 Colorado, and Be the Change joined together and chose to ignore the narrow scope of the rulemaking process. Instead, they re-upped their previously-rejected calls for a statewide moratorium and issued boilerplate statements about climate change.
The scene was summed up by Commissioner Howard Boigan who twice asked these groups what they specifically wanted:
“The context of this specific rulemaking was, convened in accordance with the notice, the scoping description of what it was going to cover. I’m asking you what you want us to do specifically today in this rulemaking that is within the framework of what we can lawfully discuss and consider today.”
Dan Leftwich, an attorney representing either could not or did not come up with any specific recommendations, again falling back onto the old talking points of halting permits.
That stood in sharp contrast to Conservation Colorado and a number of other mainstream groups that were represented by attorney Matthew Sura, who gave detailed, substantive recommendations to the commission on the standards for administrative law judges and revised forced pooling rules.
Similarly, industry officials representing trade groups and operators gave precise feedback to the commission and stated a willingness to work together.
This has put Conservation Colorado and the industry in the same lane, where both are taking a practical approach to ensure the law protects public health and the environment while creating business certainty to keep the economy strong.
Collaboration to Make SB-181 Work
SB 181 is not the first time mainstream environmental groups and industry have worked together. Last December, they agreed on a new setback distance for operations around schools that was acceptable to all parties. Colorado Oil & Gas Association President Dan Haley said at the time:
“If we take the time to work on important and complex issues together, we can find constructive solutions.”
The collaboration between mainstream groups and industry is a good-faith attempt to make SB 181 an effective law and to avoid another ballot initiative like Prop 112 – an increased setback measure – that was rejected by voters in November 2018.
Meanwhile, the activist groups who supported Prop 112 and are attempting to halt new production may soon find themselves on the outside looking in, their statements ignored by regulators and mainstream business and political leaders who have begun to focus on constructive efforts to protect the environment and grow the economy.
The post Colorado Enviros, Activists Split On Oil & Natural Gas Rulemaking Process appeared first on .
Source: Energy In Depth
Source: BOE Report