OSV OutlookI attended an excellent conference on March 3, 2016, put on by WorkBoat® exploring the “OSV Capital Outlook for 2016 and Beyond”. The conference featured a diverse and highly experienced panel of speakers including investment and marketing analysts and consultants, vessel operators, shipyard executives and WorkBoat® editors. You may want to read WorkBoat’s® own blog post about the conference; my takeaways from attending are as follows:

  • Praveen Narra, a Raymond James analyst, indicated that while oil prices appear to have bottomed and are beginning to climb toward an expected range of $65 to $70 per barrel in 2017 and 2018, a sustainable turnaround in OSV day rates and utilization should not be expected until at least 2018.
  • Mr. Narra stated that actual rig tendering activity will likely continue to decline in 2016 with no substantial uptick in day rates until 2017.
  • Richard Sanchez, a marine analyst with IHS Energy-Petrodata MarineBase, cautioned that when drilling activity does resume, it is likely to first rebound onshore rather than offshore, as onshore projects can be brought to production much faster, more efficiently and at less cost than offshore projects.
  • Sanchez is seeing that the downturn in OSV utilization is affecting shallow water platform supply vessels more than large PSVs and anchor handling tugs, with day rates for shallow water PSVs at below break-even levels.
  • Matthew Rigdon, a senior executive with Jackson Offshore Operators, cited as one of the lingering effects of this downturn the loss of trained, certified and licensed labor to operate vessels when the rebound finally does occur. Many mariners will move to jobs in other industries. Additionally, U.S. Coast Guard certification requirements necessitate expensive periodic training and recertification, the cost of which is traditionally shared between OSV operators and the mariners. Many out-of-work mariners may not have the means or inclination to maintain these certifications, which will shrink the pool of qualified labor available when their services are needed.
  • Allen Brooks, managing director at PPHB, LP, cited as the “elephant” in the rig market the degree of debt-load of drilling companies. This also is a significant concern for OSV operators. High debt service obligation coupled with diminished cash flows due to low utilization and low day rates will lead to substantial destressed asset activity. However, the amount of this activity is unknown. It is also unknown when investors will begin to seize the opportunity to acquire these assets.

Armed with knowledge of the bleak outlook, OSV operators should be pro-active in making decisions regarding stacking of vessels, redeployment or laying off personnel, cost cutting and restructuring debt-loads. Bankers are traditionally hesitant to repossess OSVs. There is significant costs in storing and maintaining them pending resale and these costs could mount if, as is the case now, prospects for an advantageous resale are dim. It should be emphasized that the current downturn in the OSV market does not only affect the Gulf, but is a global phenomenon. Thus, there will be no buyers for these vessels until the market begins to rebound. This gives OSV operators leverage in restructuring negotiations. [On that note, see my post of November 23, 2015.]

Greek Offshore Hydrocarbon Bid MapGreece has initiated its tender process for offshore oil and gas (hydrocarbons) exploration as of August 26, 2014. The Greek Ministry of Environment, Energy and Climate Change is seeking bid applications for its offshore oil and gas exploration in 20 block areas in the Ionian Sea and south of Crete. The Greek government is hoping this will aid the Greek economy by encouraging an influx of investment capital.

Greece is utilizing a licensed-based system where applicants will have to acquire certain licenses in order to qualify as operators. Successful bidders will be awarded exploration and development rights for a primary term of eight years which will be subject to extensions. The Greek government has made several concessions with the objective of making the process more attractive to investors and international oil and gas companies. Paramount among these is a substantial decrease in its corporate tax rate from 40% to 25%. The 25% consists of a 20% income tax and a 5% regional tax.

The submission deadline ends six months after the date of initial publication (August 26, 2014), which will be February 27, 2015. The Ministerial Decree calling for tenders is available online.

New Orleans Attorney Joanne Mantis


Guest blogger Joanne Mantis is a multilingual attorney in the New Orleans office of King, Krebs & Jurgens. She is a member of both the Louisiana and Greek Bar, and represents a variety of clients both domestically and internationally. She has previously blogged for Offshore Winds regarding the Greek Tonnage Tax.

 

Bureau of Ocean Energy ManagementThe Center for Sustainable Economy, a non-profit public interest consulting firm, filed a lawsuit today against the Bureau of Ocean Energy Management (BOEM) in an attempt to halt that agency’s first approved five-year Outer Continental Shelf (OCS) Oil and Gas Leasing Program since the BP oil spill. The Program, which establishes a schedule for 2012-2017 to be used as a basis for considering where and when oil and gas leasing might be appropriate in both the Gulf of Mexico and Alaska, received final approval from U.S. Department of the Interior on August 27, 2012.

The Center for Sustainable Economy contends that the BOEM’s implementation of the Program was a hasty, uniformed, and illegal course of action. In a press release, the Center stated that “[i]ncomplete and flawed economic analysis led BOEM to rush ahead with new offshore leases that may not be economically justified in violation of the National Environmental Policy Act, Outer Continental Shelf Lands Act, and Administrative Procedure Act.”

Industry leaders and GOP members on Capitol Hill certainly are opposed to the lawsuit. E2-Wire, an energy and environmental blog based in Washington D.C., reports that “a number of industry groups—including the American Petroleum Institute and the International Association of Drilling Contractors—have also petitioned the appeals court to intervene in the case on Interior’s side, noting their interests are at stake in the case.” While they believe the Program is too modest and should have made more Outer Continental Shelf areas available for drilling and energy exploration, they recognize that the Center’s success in the litigation would be another setback for an industry still coping with the aftermath of the BP oil spill.

The lawsuit was filed in the United States Court of Appeals for the District of Columbia.

Middelgrunden Wind Plant (HC Sorensen, Middelgrunden Wind Turbine Cooperative, NREL/Pix 17855

On May 14, 2012, the Bureau of Ocean Energy Management (BOEM) announced a finding of “no competitive interest” with regard to a proposed right-of-way grant area off the Mid-Atlantic coast for construction of an offshore wind energy transmission line. While BOEM’s decision represents a key step forward for this federal offshore wind farming project, two fast-moving projects off the coast of Texas suggest that development in waters under state jurisdiction may well have the inside track over federal projects, due to a more streamlined regulatory process. In addition, offshore wind projects along the Gulf Coast benefit from a general population more welcoming to offshore industry, as well as a high concentration of marine and offshore industrial fabricators and service companies that give the Gulf Coast a competitive advantage with lower construction, operation, transportation and maintenance costs.

The Coastal Point Energy project has been licensed for testing by the Texas General Land Office and contemplates installation (planned for the end of 2011 but apparently delayed) of a test wind turbine on a platform in shallow Texas waters of the Gulf of Mexico. Ultimately, Coastal Point plans to spend $720,000,000 on a 300 megawatt wind farm 8.5 miles off Galveston on 12,350 leased acres.  Additionally, the Army Corps of Engineers is developing an environmental impact statement, anticipated to be completed in 2014, for a second project under development by Baryonyx Corporation, Inc.  Baryonyx holds leases in Gulf of Mexico state waters, offshore Willacy and Cameron Counties, and proposes to construct an approximately 300-turbine wind farm.

As the Gulf Coast offshore wind industry continues to develop, it brings with it supply chain manufacturing and related job growth.  An example of the potential for such economic development is the manufacturing facility established by UK-based Blade Dynamics at the Michoud Assembly Facility in New Orleans East.  Incentivized by state tax credits and worldwide demand for wind turbine parts, the company is hiring hundreds of workers. This type of green energy industrial development bodes well for the economic future of a region whose prospects were severely compromised by the Obama Administration’s drilling post-BP spill drilling moratorium and general hostility to the oil and gas industry that traditionally has been the backbone of the area economy.

Image from www.inquisitr.com

With 2011 in the rearview, businesses all over the country are looking forward to fresh start in 2012.  But the opportunity to start fresh will elude natural gas producers partaking in hydraulic fracturing operations, as recent events in Ohio have caused additional uproar concerning the practice.  On December 30, 2011, Ohio state officials ordered the indefinite closure of a fluid-injection well in Eastern Ohio.  The injection well, which is 9,200 feet deep and used for the disposal of used hydraulic fracturing fluids, was shut following a series of low-level seismic events in the area.

During the eight months preceding the closure, the Ohio Department of Natural Resources (ODNR) recorded ten seismic events within two miles of the well.  None of the seismic events registered above a magnitude of 2.7 (the threshold for surface damage is generally considered to be 4.0).  The ODNR acknowledged that there is no clear and direct correlation to drilling at the site of the injection well and seismic activity.  Nevertheless, the mere presence of the seismic activity was enough for Ohio officials to take action in light of the relatively low frequency of seismic activity traditionally occurring in the area.  Thus, the well was closed.  Then, on December 31, 2011, a 4.0 magnitude earthquake struck the area.  That prompted the Director of the ODNR and Ohio Governor John Kasich, who is a supporter of oil and gas exploration and spearheaded the opening of Ohio’s state parks and other public lands  to hydraulic fracturing operations in 2011, to halt the planned opening of four nearby injection wells indefinitely.

Scientists have opined that the cause of the seismic activity could be that some of the wastewater injected into the well may have migrated into deeper rock formations, allowing an ancient fault to slip .  While similar links between disposal wells and earthquakes have been suspected in Arkansas and Texas, this issue is the first of its kind in Ohio.

The events in Ohio represent yet another blow to hydraulic fracturing operations and may be representative of a tough year for the industry in 2012.

Last month, I looked at the EPA’s November 2011 plan to study the potential impacts of hydraulic fracturing on drinking water resources and the implications of that plan for oil and gas producers. A new draft report issued by the EPA may be an early indicator that the EPA will, indeed, find that hydraulic fracturing adversely impacts those resources.

On December 8, the EPA released a draft report concerning its analysis of groundwater contamination near Pavillion, Wyoming.  The EPA began studying contamination in the area three years ago at the request of residents in the area who were concerned about contamination in private drinking water wells.  According to the draft report, the contamination likely was caused by the hydraulic fracturing process utilized in a nearby gas field.

To conduct its analysis, the EPA obtained samples from (1) two deep monitoring wells it constructed in the aquifer from which the drinking water in the area is obtained and (2) Pavillion area drinking water wells.  In short, the samples from the deep monitoring wells in the aquifer showed high methane levels, synthetic chemicals consistent with gas production, and hydraulic fracturing fluids that exceeded Safe Drinking Water Act standards.  The samples from drinking water wells also showed methane, other petroleum hydrocarbons and other chemical compounds, which the EPA concluded was consistent with migration from areas of gas production. Detections in drinking water wells are generally below established health and safety standards.

If the EPA’s findings from Wyoming are confirmed, the Safe Drinking Water Act, the Clean Water Act, the Oil Pollution Act of 1990, and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) all could be implicated.  The EPA could even seek to utilize these existing statutes, which contain significant penalty provisions, to address the investigation or cleanup of groundwater contamination caused by hydraulic fracturing. And while the EPA recognizes that the findings in Wyoming are specific to Pavillion where the hydraulic fracturing is taking place in and below the drinking water aquifer and in close proximity to drinking water wells – it did not exclude the possibility of similar findings in different production conditions in other areas of the country. Accordingly, this issue should be monitored by oil and gas producers that use or plan on using hydraulic fracturing in their production operations.

The EPA’s draft report is open to a 45-day public comment period and subject to a 30-day peer-review process led by a panel of independent scientists.  The public comment period ends on January 27, 2012.  If you would like to chime in, instructions for doing so can be found here.

The EPA issued drafts of two vessel general permits seeking to regulate discharge from commercial vessels (military and recreational vessels are excluded) on November 30. The draft permits (1) Vessel General Permit for Discharges Incidental to The Normal Operation of Vessels (VGP) and (2) Small Vessel General Permit for Discharges Incidental to The Normal Operation of Vessels Less Than 79 Feet (sVGP) address environmental risks relating to ship-borne pollutants and invasive species from ballast water discharges. The new standards, if approved, will require commercial vessels to install technology strong enough to kill at least some of the fish, mussels and other organisms in ballast water before it’s dumped into harbors after ships arrive in port. The EPA’s brief overview of the two draft permits can be found here.

The draft VGP, if approved, will replace the current VGP (effective February 6, 2008) and will impose numeric ballast water discharge limits for most vessels. The draft VGP also contains more stringent effluent limits for oil to sea interfaces and exhaust gas scrubber washwater.

The draft sVGP, which is an entirely new permit, would authorize discharges incidental to the normal operation of non-military and non-recreational vessels less than 79 feet in length. Currently, a Congressional moratorium (initiated by Public Law 110-299 and subsequently extended by Public Law 111-215) exempts all incidental discharges, with the exception of ballast water, from commercial fishing vessels and non-recreational, non-military vessels less than 79 feet in length from having to obtain a Clean Water Act permit until December 18, 2013.  When the moratorium expires, the draft sVGP, if approved, would provide permit coverage for such vessels.  However, vessel owners/operators will be required to complete the sVGP Permit Authorization and Record of Inspection form, which must be signed and maintained onboard the vessel for the entire permit term.  Moreover, vessel owners/operators will be required to conduct an annual self-inspection and certify that he or she has done so by signing the form each year.

Undoubtedly, the drafts will be subject to much debate during the 75-day public comment period and beyond.  Comments can be submitted during the comment period online at http://www.regulations.gov (instructions are provided), by email to ow-docket@epa.gov, or by mail to Water Docket, U.S. Environmental Protection Agency, Mail Code: 2822T, 1200 Pennsylvania Avenue NW Washington DC 20460 Attention Docket ID No: EPA-HQ-OW-2011-{place appropriate number here} (0141 for VGP; 0150 for sVGP).  Additionally, the EPA will hold two public meetings and one webcast to give an overview of the proposed permits and to take comment. The webcast date and time has not been established, but the meetings are scheduled as follows:

1. January 11, 2012, 9:00 am – 5:00 pm (EST) or until all comments have been heard at EPA East 1153, 1201 Constitution Ave NW, Washington DC 20460;

2. January 23, 2012, 10:00 am – 5:00 pm (CST) or until all comments have been heard at Ralph H. Metcalfe Federal Building, Room 331, 77 West Jackson Blvd, Chicago IL 60604.

Following the public comment period, the EPA anticipates releasing a final draft of the permit in November 2012.

The U.S. Coast Guard has proposed significant changes to the regulations concerning the Inspection of Towing Vessels and arguably eliminating the class of vessels formerly known as uninspected towing vessels.  The Coast Guard has established a deadline of December 9, 2011, to receive public comments, which can be made at the following link:  www.regulations.gov and by inserting “USCG–2006–24412” in the box marked “Keyword” or “ID.”

The proposed regulations cover a number of industry sensitive topics, including:

(1)   adoption of Towing Safety Management System approved by licensed third party auditors, surveyors or classification societies or annual inspections by the Coast Guard

(2)   propulsion / steerage redundancy requirements as well as stability and electrical design requirements

(3)   crewing/manning training requirements including record keeping functions

As of this writing, several industry stake-holders have posted comments concerning the anticipated costs of compliance on small operators, the inconsistencies between the proposed regulations of towing vessels and the absence of similar regulations for passenger vessels, as well as the absence of any “grandfather” provisions as had been provided when previously “uninspected” vessel classes were thereafter subject to regulation.

Rep. Jeff Landry (R-LA) has added a provision to the Coast Guard and Maritime Transportation Act of 2011, currently under consideration in Congress, which would require the owner/operator of any offshore rig or vessel engaged in drilling, plugging and abandoning or workover operations to maintain a standby rescue vessels within 3 nautical miles.

The provision is being applauded by those who believe it is an appropriate safety measure in the wake of the Deepwater Horizon blowout that resulted in the deaths of 11 workers and the rescue of 115 others by a supply boat that happened to be alongside the rig at the time.  The requirement also could also create additional work for vessel operators in the Gulf of Mexico.  But there is opposition to the measure, even by other legislators in Rep. Landry’s own state.  Rep. Charles Boustany (R-LA) has criticized it, saying “It would create excessive regulations on energy producers and hinders the progress we have made in order to restart Gulf energy production.”  Additionally, the measure would allow the use of one standby vessel for more than one manned facility or vessel, and the use of standby vessels for purposes other than rescue.

Vessel operators interested in providing the rescue services called for in the bill therefore could face some difficult operational decisions and even liability concerns.  Accordingly, close attention to risk-allocation, indemnity and insurance provisions in agreements to provide these rescue services would be highly recommended.

For further coverage on Landry’s proposal:

Louisiana Oil & Gas Association

The Times-Picayune

On November 3, 2011, the U.S. Environmental Protection Agency (EPA) released a plan to study potential impacts of hydraulic fracturing on drinking water resources.  The study, which is being conducted pursuant to Congress’s request, will focus on the effect of hydraulic fracturing in shale formations on drinking water sources during the five stages of the hydraulic fracturing water lifecycle:

(1)  water acquisition;
(2)  chemical mixing;
(3)  well injection;
(4)  flowback and produced water; and
(5)  wastewater treatment and waste disposal.

The primary focus of the study is on the use of hydraulic fracturing in shale formations, but it is expected that information relevant to hydraulic fracturing in other types of unconventional oil and gas reservoirs (i.e., coal-beds and tight sands) will be included.

While it is impossible to predict the outcome of the EPA’s study, oil and gas production companies should monitor the EPA’s progress on this subject. If the EPA concludes that hydraulic fracturing has an adverse impact on drinking water resources, the consequences could be severe.  In that scenario, new rules and regulations certainly could be imposed and, depending on the extent of any such regulations, could impact the costs of production.  Additionally, the findings could implicate existing rules and regulations, such as those set forth in the Safe Drinking Water Act and the Clean Water Act, and subject production companies to penalties.

Considering the existence of studies estimating that 80 percent of natural gas wells drilled in the next decade will require the use of hydraulic fracturing, the cost of bringing hydraulic fracturing operations into compliance with new or existing regulations could be considerable.  Also, if the EPA’s findings are substantial and garner public attention, a knee-jerk reaction imposing a temporary moratorium on hydraulic fracturing is not beyond the realm of possibility.  Clearly, that is the worst case scenario from the viewpoint of production companies and their employees, but it is a possibility in light of recent governmental actions taken in connection with the Deepwater Horizon matter.

On the other hand, production companies may have little with which to be concerned.  In 2004, the EPA concluded that the injection of hydraulic fracturing fluids into coal-bed methane wells produces little or no threat to underground sources of drinking water.  While the 2004 study is entirely different than the EPA’s current study and is not indicative of the results that will be reached in this instance, it does show that a negative finding – hydraulic fracturing has no adverse affect on drinking water resources – cannot be ruled out.

The EPA has announced that its initial research results and study findings will be released to the public in 2012. The final report will be delivered in 2014.