The big question is: How many deepwater rigs will be left once drilling restarts?
Terry Childs, RigData Offshore
The Deepwater Horizon blowout and the ensuing environmental and political fallout have thrown the US Gulf of Mexico deepwater rig market into chaos and put the near-term future of the industry into question. Shallow-water operations have not gone unaffected, either, as permit approval delays have put the brakes on what was a slightly improving jackup market. Meanwhile, rig age requirement changes by Pemex could alter the rig landscape in Mexico and in the US Gulf.
U.S. GULF DEEPWATER RIGS
On April 20, 2010, the deepwater US Gulf of Mexico drilling market was turned upside down with the blowout and sinking of the Deepwater Horizon semisubmersible and the ensuing oil leak, which didn’t cease until July 15, when an experimental cap choked off the flow of oil from the well. As a result, uncertainty is the word of the day in this market. There is uncertainty regarding the ultimate resolution of the most recent drilling moratorium. There is uncertainty as to what, if any, future legislation (mandated equipment requirements and/or modifications) might come out of Congress. There is uncertainty as to how quickly future drilling permits will be processed. There is uncertainty as to how much drilling costs will rise in response to the newly imposed safety regulations, not to mention the lifting of the $75 million oil spill cleanup liability cap for operators. The bottom line is this: The new rules are not completely clear to rig owners, operators or even to the government, and no drilling is going to take place until everything is fully understood by everyone. As a result, generating an outlook for this segment of the rig fleet is a difficult task at best.
Before the blowout, there was apparent softening in the US Gulf floating rig market. Two semis were most likely going to go idle within the next few months, and several other units had sublet time available that was not being filled. As a result, the few new contracts and extensions taking place were at decent day rates, but well below the levels seen the past few years.
Now, however, the market finds itself in an unprecedented position. Aside from the political and legislative concerns, two other burning questions are how many (if any) rig contracts will be terminated via force majeure and, second, how many rigs will leave the Gulf. As for the first question, force majeure has been declared publicly on eight rig contracts to date and one contract has been terminated (Anadarko’s contract for the semi Noble Amos Runner). How many more force majeure declarations will be made and contracts terminated remains to be seen, but it would be safe to assume there will be more. However, neither rig owners nor operators want to see a court case develop, and to that end, Diamond Offshore became the first rig owner to secure work outside the US Gulf when the semi Ocean Endeavor left in July for a 250-day contract plus options with Burullus Gas Company off Egypt starting in October or November. Work will last through June 2011, and Diamond believes there will be additional opportunities for the rig in the area thereafter. As part of the deal, Devon Energy, which the rig was working for in the Gulf, paid a $31 million early termination fee. That deal was followed by Murphy Oil agreeing to take the Ocean Confidence to the Republic of Congo for a three-well-plus-option program. The rig, however, will return to the US Gulf for a one-year term provided Murphy is satisfied it can obtain necessary drilling permits.
At the time of this writing, rumors were also swirling that the Ensco 8501 and Ensco 8502 would both be sublet to operators for work outside the US Gulf, but no other details were known. Other reports have Statoil moving the semi Maersk Developer to Egypt and Eni taking the Transocean Marianas to West Africa. Should these rumors prove to be accurate, it would make six departures in fairly quick order, not a good start for the market.
Prior to Diamond’s announcements, Noble Drilling was the first rig owner to renegotiate a contract when Noble Energy agreed to pay a standby rate for the Noble Clyde Boudreaux semi, effective from June 15 to Dec. 12 with an option to extend the period if necessary. In addition, the parties agreed to reduce the existing $605,000 day rate down to $397,500 for the remaining 17 months of the contract, originally scheduled to end in November 2011. Noble also renegotiated and extended its contract with Shell for the semi Noble Jim Thompson, receiving a three-year extension, with the contract to be suspended during the drilling stoppage. In addition, the day rate will be reduced from $505,000 to $336,200. More recently, Transocean reported that it had renegotiated contracts with BHP for the GSF C.R. Luigs and the GSF Development Driller I. The operator will pay a reduced rate for the period it is unable to drill, but the day rates will remain where they are once the contract resumes. Transocean also negotiated a similar deal with Shell for the Deepwater Nautilus semi. The contracts for all three rigs will also be extended for a period equal to the drilling stoppage. The rig owner is also still in talks with Chevron over force majeure declarations for the Discoverer Inspiration and Discoverer Clear Leader and with Statoil on the Discoverer Americas. With many of these renegotiations now in place, others will no doubt follow, but only a handful of operators will be willing and/or able to pay a standby rate for a rig (or rigs) that may not work for six months or more.
With regard to when drilling might restart, that is anyone’s guess. After losing two court battles, the Obama administration issued its promised revised drilling moratorium on July 12. The new version bans all drilling operations using subsea BOPs as well as those using surface BOPs on floating facilities. Unlike in the original moratorium, water depth is not referenced, and it is believed that the new moratorium will affect floating rigs even in water depths less than the original 500-ft cutoff.
However, there are also two positive changes to note. First, the new order contains an “official” moratorium end date of Nov. 30, 2010, which is a bit shorter than the implied date in the original version. Second, Interior Secretary Ken Salazar did allow the new Bureau of Ocean Energy Management, Regulation and Enforcement to provide further evidence as to whether development and/or appraisal drilling should resume earlier than Nov. 30. It is expected that the new moratorium will be challenged in court and possibly overturned again. However, no matter which way it goes, drilling will not begin anytime soon.
In the meantime, the question remains: How many rigs will be left in the Gulf once drilling does restart? The short answer is that no one knows, as there are still too many unsettled issues, political and otherwise. However, there appear to be two possible scenarios. Should all the issues associated with the moratorium be settled by Nov. 30, as few as seven to 10 rigs might leave. Should the perception be that things will drag out longer, operators will be more prone to move rigs, in which case 10–15 or more could easily leave. The likelihood of the latter might increase, since at this point no one knows what the regulatory regime will look like after Nov. 30. Should a contractor be presented with the opportunity to move a rig out of the Gulf, there likely will not be much hesitation. Obviously, every operator drilling in the US Gulf that also holds international acreage is looking for opportunities, but operators will only move a rig if it makes economic sense.
It is difficult to estimate how future US Gulf day rates will be affected. As evidenced by the Noble Drilling deals, it is probably safe to say that most rates are headed down, but by how much is uncertain since every contract is different. On the other hand, rates would not change for the rumored Ensco sublets. For some contracts, rates may go down in exchange for longer terms if that makes sense for both parties. There are simply too many variables to allow solid prediction of how rates will change. While it may be safe to say that a decline is inevitable, rates will likely still be at levels that operators and rig owners can live with.
The final outcome of the moratorium and regulatory reform is still uncertain to all involved, and drilling will not rebound in earnest until the operator community gets comfortable with what regulations and costs are going forward. Never before has the US deepwater rig market had to overcome an event of this magnitude, so it will no doubt be interesting to watch. It obviously will be a struggle for the market to recover, but in the end deepwater drilling should remain a big part of activity in the Gulf.
U.S. GULF JACKUP MARKET
Shortly after the initial deepwater drilling moratorium was put into place, word surfaced that it would be extended to all federal waters in the US Gulf. For a short period, it seemed that no one, including the US government, knew exactly what was going on. Then, it was determined that operations in under 500 ft of water would not be included, so it was thought that the jackup market might escape unscathed. That has proven not to be the case; delays in well permit approvals have resulted in idle time for several rigs, some lasting a month or more. While some of the rigs have been waiting on location and on payroll, others had not moved yet and, thus, have no income during the wait. As of mid-July, no fewer than 11 jackups were waiting for permits to be secured in order to begin new wells or contracts.
As a result, a number of force majeure declarations have been made by both large and small operators. One contract, Arena Offshore’s deal for Diamond Offshore’s jackup Ocean Scepter, has been terminated. The contract had about a month left, after which the rig was scheduled to head to Brownsville to prepare for its upcoming one-year contract off Brazil later this year. Most force majeure declarations, however, have been rescinded after operators were able to get the necessary permits. In addition to force majeure, some programs have been postponed until later in the year, which has also sent rig owners scrambling to try and fill rig time previously thought to be booked.
Clearly, operators and rig owners alike have been frustrated with the situation, and one rig owner, Rowan, has hinted that it would like to move every jackup possible out of the Gulf. To that end, it is understood that the company is close to securing contracts with Saudi Aramco for the jackups Bob Palmer and Ralph Coffman, each for a three-year term, with work beginning in December. While there are still some other US Gulf jackups that could move to other parts of the world, the likelihood of a meaningful number of departures is low.
During the past five years, jackup supply in the US Gulf has dropped overall by an average of 23 rigs. The 2006 average fleet of 103 rigs fell to 80 by mid-July 2010. As for marketed jackups, which excludes cold-stacked units and is the supply number most watched in the industry, the fall was much greater, going from 85 in 2006 to 49 in June 2010, a 36-rig decline. From the numbers, it is easy to see that during that period a large number of jackups went from marketed to cold stacked, meaning a lack in demand existed. A further look at the data shows that the number of rigs under contract went from an annual average of 69 in 2006 to 35 in July 2010, following right along the lines of the drop in marketed supply, Fig. 1. Natural gas prices have historically been considered the major factor in determining Gulf jackup activity, and since peaking in mid-2008, both gas price and jackup utilization declined steadily for the next 15 months to September 2009, Fig. 2. For the remainder of 2010, gas prices are forecast to range $4.50–$5.20/MMBtu. Should that prove to be correct, the jackup demand level will not change much.
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Fig. 1. Total supply, marketed supply and demand for jackups in the US Gulf.
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Fig. 2. Jackup rig utilization and natural gas price.
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Commodity jackups have been, as would be expected, the hardest-hit portion of the jackup fleet. As of July 15, for instance, there were no 250-ft mat/slot jackups under contract, whereas prior to April 20, six of the seven marketed units had contracts. These jackups essentially have no options other than riding out the storm. Some layoffs have been documented, but they have not been widespread.
Day rates, which had been slowly moving up, will undoubtedly weaken in the coming months. The handful of new fixtures agreed to since April 20 have all remained close to existing rate levels. However, if rigs continue to idle, it is only a matter of time before they head down, particularly within the commodity fleet, as this is where most of the idle equipment is. The premium jackup fleet, those rigs rated for depths of 250 ft and greater, is essentially at 100% utilization, and day rates for these rigs are not likely to change much. Rates for mat jackups have hovered slightly above operating costs in most cases. With a range in the low to mid-$30,000s, there is not much room left before operating costs are reached, so they likely will not fall below the high $20,000s, probably staying in the low $30,000s.
PEMEX ALTERS JACKUP STRATEGY … AGAIN
For the second time in three years, Mexican state oil company Pemex has altered its requirements for jackup rigs to work offshore. On Oct. 23, 2007, the mat-supported jackup Usumacinta collided with a platform, resulting in a total-loss accident of the rig. After a lengthy investigation, Pemex said it would replace all its mat jackups with independent-leg units. At the time of the accident, there were 16 mat units operating in the Bay of Campeche, 14 of which were US-owned. As contracts began to expire, mostly in 2009, the mat-supported units were indeed released, and since then 13 of the 14, plus two independent-leg units, have been mobilized back to the US Gulf. Many of the replacement independent-leg units were plucked from the US Gulf, which has helped offset the influx of mat rigs back to the region somewhat. The market was able to absorb five of the returning mat units, though the eight remaining mat units and both independent-leg units were cold stacked. Now, however, independent-leg jackup owners in the US Gulf are holding their collective breaths as Pemex has announced another wrinkle in its jackup policy, one that could ultimately send several rigs back to the US Gulf, again.
Earlier this year, Pemex said it would now only accept bids for jackups that either were built within the past 10 years or had undergone major upgrades within the past 10 years. However, the upgrades required on older rigs meant they would have to be similarly equipped to new jackups, so the rule essentially allowed newbuilds only. Of the 24 independent-leg units working in the Mexican part of the Gulf as of July 15, only four meet the 10-year criterion and none are US-owned. Along with the age requirement came a day rate cap that no bid would be allowed to exceed. In past bids, rig owners could generally calculate the maximum rate Pemex would accept, but there was no set number they could not go beyond.
The question mark since the most recent announcement was whether Pemex would maintain its jackup age requirement. In its lone tender since the decision, the 10-year rule was in effect for three of the four contract awards, with the exception of the Noble Roy Butler, built in 1984, which received a 252-day contract for a project that specified a 250-ft rig. While reports indicate that an upcoming two-rig tender will also have the 10-year age requirement, not everyone thinks it will be sustained. Noble Drilling publicly stated after the new ruling that it still expected all 12 of its jackups to continue working in Mexico (since then, one of its rigs, the Noble Leonard Jones, is now idle after a direct assignment agreement was scrapped that would have extended the contract through August). Then, in a second-quarter earnings conference call on July 20, the company said it believed Pemex would shortly go out to bid for what could be 21 jackups, all to start work next February. Noble further stated that, in the previous tender, a large number of companies had purchased the bid package but very few actually submitted bids, something it was “encouraged” by given its position as Pemex’s largest driller.
Based on comments from other contractors, however, not everyone shares in Noble’s optimism, at least not completely. Some point to the fact that Pemex has proposed a record-high budget that, if approved, could lead to additional tenders. Others believe Pemex will ultimately realize it may not be able to get all the new rigs it wants and will have to settle for older equipment. However, the question of whether the oil giant could put together a bid of that magnitude in such a short period remains. Many believe Pemex is still attempting to get its arms around the new laws and that any large-scale bidding will be slow in coming.
In the meantime, older units owned by Noble Drilling and Ensco have received recent contract extensions, but all have been for six months or less. By law in Mexico, any extensions granted by Pemex must be equal to 20% of the original term. However, extensions are for a set number of days or until the current well ends. In other words, a rig owner might receive a 180-day extension, but if the current well finishes in 30 days, the rig can be released.
If Pemex holds to its 10-year requirement in upcoming tenders, the older jackups ultimately will be released and the US Gulf will get hit again with a surplus of rigs. While US demand will absorb premium units fairly easily, it is not a certainty that all the jackups will be able to find work. As of July 15, there were 12 jackup contracts scheduled to end this year, seven in 2011 and five in 2012.
As for the deepwater market, Pemex is limited in experienced personnel, cash and seismic imaging, as evidenced by the fact that it has drilled fewer than 20 deepwater wells. As of July 15, there were only three semis operating off Mexico. However, reports indicate that Pemex desires to ramp up its deepwater exploration drilling program, and it is taking steps to do just that, with two additional semis beginning multi-year contracts in late 2010 and 2011. In 2009, Pemex hired CGGVeritas to undertake the company’s largest ever deepwater seismic survey, a $464 million project that will acquire some 29,000 sq mi of 3D seismic data. Current estimates say the survey area could contain up to 30 billion boe, which would represent more than half of the country’s current total estimated reserves, and with declining shelf production, Pemex will need all the deepwater reserves it can get. Given the positive signs taking place, many analysts and rig owners believe that deepwater rig demand off Mexico could mirror that of the US Gulf within the next three to five years, making it a very real area of opportunity for rig owners.
CANADA MARKET STAGNANT
As of July 15, there are four rigs operating off Canada. One of the rigs, the Stena Carron drillship, just arrived in the area recently, but it is only expected to drill for about six months before leaving. As for the other three units, it is believed that jackup Rowan Gorilla III will head back to the US Gulf once its work in Deep Panuke Field for Encana wraps up in September. After the Stena ship finishes in early 2011, it will leave just two rigs working off Canada, both owned by Transocean. The semi Henry Goodrich recently signed a three-year extension with Husky Oil that starts in October. The semi GSF Grand Banks also inked an extension with Husky, with the new two-year term starting in January 2011. Both deals were for reduced day rates, however.
Compared to the US response, the Gulf blowout has had a mild effect on operations offshore Canada. Provincial regulators allowed Chevron to spud a deepwater well a few months ago, but it did impose a more frequent inspection schedule. Before the blowout, BP and ExxonMobil were in the early stages of planning to drill in the remote Arctic waters of the Beaufort Sea, where no drilling has taken place since 2005. Federal regulators were considering requests to ease the rules for drilling in the region, but officials have now delayed drilling until the causes of the Gulf blowout are fully understood. Despite the drilling delay, the Canadian government still plans to grant new offshore oil exploration licenses in the Beaufort Sea.
As of July 15, there were 14 drilling plans in various stages. Only three of the plans call for jackups; the rest need either semis or drillships. Three of the plans are slated for close to the offshore boundary with Greenland, one in the Beaufort Sea and the other 10 off the East Coast. Eight of the 14 plans are for one or two wells only. While some operators in the region have multi-year requirements, in many cases it would take a group of operators bundling their programs together to attract rig owners to the area.
GLOBAL IMPACT
Worldwide, the most significant effect of floating rigs leaving the US Gulf for international work is that it takes away work that would have gone to another rig, which could apply downward pressure on day rates in those areas where the rigs move. Nevertheless, most forecasts still predict a floating rig shortage in the next few years, despite the large number of rigs under construction, so in the long run, the impact of rigs moving out of the US Gulf may be largely muted. 
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THE AUTHORS
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Terry Childs is Director of Data Services and Publications at RigData Offshore in Houston. He has nearly 30 years of industry experience, starting in 1981 when he joined ODS-Petrodata’s predecessor, Offshore Data Services. After serving in a variety of research and editorial positions in the company, his last 10 years were spent tracking the worldwide and Gulf of Mexico rig markets. He left the company in 2006 for a three-year stint marketing jackups with Ensco Offshore in Houston, and joined RigData in August 2009.
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