Deepwater Gulf

The fog enshrouding the Bristow Group heliport at the mouth of the Mississippi River near Venice, Louisiana, grounding all flights to offshore Gulf of Mexico oil and gas operations this January day, is a typical pause to a changing of hands. Some 55 miles south, the Noble Amos Runner semisubmersible fourth-generation rig, under contract to LLOG Exploration Co. LLC, continued its mission of drilling out Who Dat Field in Mississippi Canyon 503. It is a two- to three-year program in 3,100 feet of water.

Who Dat came online at the end of 2011, and now has four wells producing 18,000 barrels of oil and 45 million cubic feet (MMcf) of gas per day. Randy Pick, LLOG managing director, acquisitions and divestitures, says, “A large-scale development project such as Who Dat requires a significant amount of rig time, and we have several prospects that could be as large as Who Dat.”

Such optimism pervades Gulf operators. Like a rising wave out of placid waters, projects are once again gaining momentum in the deepwater Gulf of Mexico. The regulatory miasma that halted drilling in the basin following the Deep-water Horizon rig explosion and subsequent Macondo well oil spill in 2010 is finally lifting. Visibility is clearing, and operators are eagerly resuming exploration and development plans.

Right, after taking a dive in 2009-2011, deepwater exploration and development wells are rebounding, with further growth expected. Facing page: LLOG’s Who Dat platform in Mississippi Canyon Block 503 with the drill rig Noble Amos Runner in the distance.

Jud Bailey, senior managing director, head of oil services and equipment for investment research firm International Strategy & Investment Group LLC, believes the deepwater is poised for a boom.

“Essentially, after being left for dead following the devastating Macondo blowout, we believe the deepwater Gulf of Mexico is in the early stages of an extended growth cycle and is poised to be the strongest offshore market in the world through 2015,” he said in a December 2012 report on the Gulf.

Majors and national oil companies continue to be the driving force for pushing the boundaries in the deepwater Gulf. Key areas of interest are in Alaminos Canyon, Keathley Canyon and Walker Ridge.

Statoil, the international oil company based in Norway, is an example of a company riding the wave. It entered the deepwater basin as recently as 2005, and has identified the Gulf as a growth edge.

“It’s a combination of large reserves and attractive fiscal terms,” says Jason Nye, Statoil executive vice president of U.S. offshore. “The opportunities compare very favorably with any- thing else in our portfolio, which is why we’re spending money here.”

Did post-Macondo regulation changes affect Statoil’s long-term commitment? Not at all, he says. “There is still some uncertainty, and it’s still a moving target sometimes, but in general, we see it as a fairly stable environment. Things are coming back to normal.”

A wave of capital infusion illustrates operator confidence. Sugar Land, Texas-based research and consulting firm Quest Offshore Resources Inc. forecasts total spending in the Gulf to increase 30% in 2013, to $40 billion overall, and a cumulative $167 billion through 2016. For the first time ever, deepwater spending is expected to have outpaced shallow-water spending in 2012, led by a growing number of deepwater fields.

“2012 is expected to represent an investment shift with deepwater capex and opex spending surpassing that in shallow water,” according to the report released in late 2012. And the shift is expected to intensify over the next five to seven years, outpacing shallow-water spending two-to-one by 2016.

Total deepwater spending in 2016 is forecast at $27 billion. “Increased development activity levels are expected to drive robust deepwater spending in the Gulf of Mexico in the coming years,” the report said.

Noble Energy Inc. will contribute its share; it has multiple deepwater Gulf of Mexico prospects queued up. “The Gulf of Mexico is back in business,” says John Lewis, vice president of U.S. operations, southern region. “The opportunities are there, and I don’t see it slowing down.”

Stepping beyond

The 26%-operated Gunflint, a large four-way discovery in southernmost Mississippi Canyon Block 948, represents a calculated step-out for Noble Energy—a move beyond suprasalt amplitude plays to the subsalt Miocene, the primary target of deepwater development today.

First discovered in 2008, Gunflint is estimated to hold gross resource potential of 90- to 325 million barrels of oil equivalent (BOE), including untested Lower Miocene potential. It is the company’s largest Gulf of Mexico discovery to date. Commerciality of the prospect was confirmed with the first appraisal well completed in third-quarter 2012, delayed by Ma-condo.

“We found more than 500 feet of hydrocarbon pay in the original discovery well, predominately oil with some natural gas zones,” says Lewis. “We know we have enough resources here for a commercial development.” Gunflint Appraisal #2 will spud in first-quarter 2013.

Gunflint, with wells reaching to 32,000 total feet in 6,100 feet of water, will come online in late 2015 or early 2016 if developed as a subsea tieback, or 2017 if sanctioned as a stand-alone hub.

“Based on reservoir quality, we expect these wells to be prolific—the deliverability should be strong,” says Lewis.

They won’t be the last. Subsalt exploration prospects with 743 million BOE combined gross unrisked potential can anticipate Noble Energy-operated drillbits in the next two years. These include Dantzler and Madison in Mississippi Canyon, and Yunaska in Ewing Bank.

“Below salt, seismic imaging technology continues to significantly improve our interpretations. That’s where the big potential remains,” says Lewis.

Noble Energy currently generates some 25,000 BOE per day (80% oil) in the Gulf of Mexico, essentially all from the deep water and all from amplitude plays. While exiting the shelf in the early 2000s, the Houston-based company focused its efforts on these highly economic, above-salt targets with great success. The company then expanded its attention to the subsalt Miocene in 2008.

“To grow, we knew we needed opportunities with material scale,” says Lewis, but notes the company takes a measured, strategic approach to new ventures.

Noble Energy has since amassed a resource base of about 1.6 billion barrels of net unrisked resource potential in the Gulf. “The deep water by itself has potential resources larger than Noble Energy’s entire reserves at year-end 2011,” Lewis says.

Bucking the notion that the deep water is becoming a basin for majors only, Noble Energy is a large independent operator with a global portfolio on an upward trajectory and development projects more typical of a major. “We have successfully transferred the experience and expertise we’ve gained in the deepwater Gulf of Mexico over the years to safely and responsibly create exceptional opportunities, internationally, and vice versa,” adds Lewis.

The Eastern Mediterranean and offshore West Africa are two of Noble Energy’s core operations areas. The company also holds international exploration prospects offshore Falklands Islands and Nicaragua.

“Given the resource scale we’ve captured in the deepwater Gulf of Mexico, we see great growth potential there. Exploration is a true value creator for us,” says Lewis. “We have an opportunity to bring high-margin barrels on production in a proven basin where infrastructure exists and where we’ve had success. It’s material to Noble Energy going forward.”

Noble Energy has the distinction of being awarded the first deepwater permit to drill a well post-Macondo, as well as having the first exploration discovery after the incident. The company was twice awarded the Safety Award for Excellence (SAFE) immediately before Ma-condo, and assumed a leadership role in a partnership with 23 other dependents to create the Helix Well Containment System post-Ma-condo.

But don’t think Noble Energy has abandoned amplitude plays. Its Big Bend discovery in November, in which it has 54% interest, shows potential—an estimated 30- to 65 million BOE. As subsea tie-backs, drilled to 17,000 feet for about $75 million gross, these shallow amplitude plays remain very profitable, he says. “We can get them on line fast with very productive wells.”

deepwater drilling permit approvals surged in 2012.

Troubadour, next door, could double the potential. Noble Energy holds 87.5% in this prospect scheduled to be tested later this year. These two fields should be developed together, with first production expected in late 2015 or early 2016.

Noble Energy has not yet pursued emerging Lower Tertiary prospects like other deepwater operators. “We understand the Miocene,” says Lewis. “It’s our core area. Big discoveries, especially subsalt, remain to be found here as imaging continues to improve.”

That could change, however. “We see potential for significant resources not only in the Miocene, but other horizons,” he says. “We see new opportunities we haven’t played before.”

The company picked up several remote blocks in Atwater Valley called Chadwick. “We haven’t drawn a line that we can’t go deeper,” he says. “We’re not limiting ourselves.”

Nor stepping back. “The scale of the projects we do is on par with what any supermajor does. We’re not intimidated by technical challenges. We have the technical capability to efficiently execute large-scale projects.”

Noble Energy has Ensco rig 8501 under contract for its upcoming Gunflint appraisal well and has multiyear options to extend that contract. The company also shares a one-third-interest contract with Ensco 8505. “Our strategy is to keep one rig drilling exploration, then let follow-up development needs determine the rigs we’ll add after that. I think we’ll be adding rigs, but the timing will be a function of success,” he says.

Lewis says Gulf of Mexico capex will total about $300 million in 2013, about 10% of the company’s total. “We see a lot of opportunities here, and we’re poised to take advantage of them.”

Project backlog

Could the flurry of deepwater activity be only a temporary surge of pent-up projects? Possibly.

The impending wave of deepwater development projects is a result of both the Macondo downtime, as well as the preceding financial crisis, according to Quest Offshore consulting manager Sean Schafer. “A lot of projects got held up. Now they’re all hitting at the same time.”

A rise in permitting reflects this. Multiwell campaigns using a single rig are being issued permits regularly, driving permits to near pre-Macondo levels. On the flip side, regulators are taking their time reviewing true wildcat exploration permits.

“As a regulator, you’re going to be more reticent of an exploration well over a development well,” says Shafer. “In a development well, the reservoir has already been penetrated and the geology is known. There’s less risk.”

Quest Offshore calculates permits issued for multiwell projects account for 44% of exploration permits and 62% of development drilling permits from October 2011 through September 2012. Pre-Macondo, multiwell exploration permits accounted for less than 1% and development permits for less than 2%.

But true exploratory drilling, defined as an undrilled prospect, is definitely down relative to total drilling in the Gulf, he says. “Operators are at a point where they want to develop their projects and get them into production, but at some point you’ll run out of new reserves to develop if they don’t return to exploration. The Gulf needs wildcat exploration.”

ISI’s Bailey notes the same trend. “We forecast the balance between exploration and development wells drilled in the deepwater Gulf of Mexico to return to roughly 50-50 for the first time since the early 2000s, which implies almost three times the annual development activity as the peak of the last deepwater cycle in 2006-2008.”

Large independents are expected to grow their share of the floating rig count in coming years.

Who Dat

LLOG Exploration Co. LLC, founded in 1977, is a large private company that historically liked to operate under the radar. However, the Covington, Louisiana-based operator stepped into the spotlight in 2011 when it became the first privately held company to own and operate a deepwater floating production facility on its Who Dat prospect.

It captured the limelight again when it entered into a $1.2-billion partnership with global private-equity giant Blackstone in November. Not afraid to play alongside the big boys, LLOG (pronounced “log”) is poised to be a significant player in the deepwater Gulf.

“There is room to find plenty of significant fields in the Gulf of Mexico,” says Rick Fowler, LLOG vice president of deepwater projects. “We’re confident in our ability to execute.”

The multibillion-dollar company operates both in the shallow and deep waters with total company production of about 34,000 BOE per day, 60% oil. But current gas prices have pushed virtually all of its capital investment toward oil-rich targets in the deep. There, daily production represents some 28,000 BOE, with proved and probable reserves in excess of 200 million BOE.

With 147 blocks in the portfolio, LLOG has identified 40 deepwater prospects, of which 15 are considered “hub class”—larger than 50-million-barrel potential and able to support a standalone production facility. LLOG operates 95% of all of its production and touts a 70% success rate. Its core area is in Mississippi Canyon in 3,000 to 5,000 feet of water targeting the Miocene trend.

“The central Gulf is our bread and butter; we focus most of our activity there,” says Fowler.

When the drilling moratorium took effect post-Macondo, LLOG kept the Noble Amos Runner rig busy completing seven deepwater wells. Three of those were in Who Dat Field, a 100- to 300-million BOE potential discovery that it sanctioned just a month after the incident. When it commissioned the Who Dat floating production facility (FPS) during the moratorium, “many considered that a bold move because we didn’t know if we would be allowed to drill or even produce anymore,” Fowler says.

Since the Exmar platform was built on spec, LLOG was able to purchase the facility, make necessary modifications, and put it online in under a year, a record. It is LLOG’s first FPS. Who Dat (“Who dat say dey gonna beat dem Saints?”) has capacity of 60,000 barrels and 150 MMcf per day. Exmar financed the acquisition over 62 months, further freeing LLOG capital.

Far left, the most recent lease sale in the Gulf exhibits a reversal in spending, with the majors vastly outspending independents. But the latter still outpace the majors on total blocks leased.

“We expect to have 14 wells coming into that facility, and do think we’ll use up the capacity,” Fowler says.

Next up: Delta House. This second FPS will accommodate nameplate capacity of 80,000 barrels and 200 MMcf, with peaking capacity of 100,000 barrels and 240 MMcf. “This one is going to be significantly larger than Who Dat, and will accommodate a number of fields,” Fowler says.

Those fields include Marmalard in Mississippi Canyon Block 300, drilled to total depth of 18,100 feet, and Son of Bluto II, affectionately known as SOB 2, in Mississippi Canyon 431, total depth 18,500 feet. These are LLOG’s first exploration wells since Macondo.

Showing its confidence, LLOG began engineering and requested bids from fabrication yards for Delta House ahead of any discoveries. “We felt confident that ultimately we would need it. We designed a unit that would work for any of our hub class prospects,” Fowler says. The FPS is financed by ArcLight, which will have majority ownership interest once completed.

When LLOG, the largest private operator in the Gulf of Mexico, entered into a five-year joint-venture partnership with Blackstone, it was a seismic shift from its grow-within-cash-flow history and a sign of the ripening opportunities offshore. The partnership is the largest private-equity financing executed in the Gulf of Mexico to date. The funds will accelerate development of LLOG’s four recent discoveries and appraisal of new discoveries, increase participation at federal lease sales and farm-ins, and provide the opportunity for acquisitions.

Scott Gutterman, LLOG chief executive, said at the time of the announcement, “This transaction is indicative of the many exciting assets and opportunities we have at LLOG and will enable us to capture opportunities that we could not otherwise pursue. We believe the Gulf of Mexico deepwater is one of the most attractive oil plays in the world, and we expect to continue to be a long-term, significant player in the basin.”

In 2013, LLOG anticipates drilling up to 10 gross deepwater wells, with much of the capital spend directed at the Delta House project and associated subsea systems. LLOG total net capital in deepwater projects in 2013 will top $600 million.

Says Fowler, “We’re able to drill a lot more prospects and pursue additional opportunities that we would not be able to pursue if we were using all LLOG funds. I don’t feel any capital constraints right now.”

Counting rigs

If rig count at the time of Macondo is a measure, present-day 38 deepwater floaters top the 33 in April 2010. And there is no plateau in sight: Quest Offshore anticipates some 60 floating rigs operating in the deepwater by 2016—a doubling since Macondo.

Besides the Macondo stoppage, the preceding financial crisis and drop in oil and gas prices stunted basin activity as well. Now, Brent crude prices near $100 motivate operators to develop deepwater oil targets.

“The Gulf of Mexico is rich with opportunity,” says Leslie Cook, Quest Offshore senior research consultant. “With oil projects in the Lower Tertiary and deeper waters, operators know the potential for good returns on their investments, but these reservoirs are challenging and they need the type of rigs that can safely drill the wells.”

Slower permitting times also push the rig count up, as more rigs are needed to drill the same number of wells.

Not only are more rigs coming in, the makeup of the fleet is changing. For the first time, 90% of the rig fleet is rated as ultra-deepwater rigs (up to 12,000 feet of water), even though only four currently operate at water depths of 7,500 feet or greater.

“That’s huge,” says Cook. “Everything ordered and under construction now are ultradeepwater drillships, as opposed to semisubmersibles. That’s the trend going forward.”

The rig profile change began pre-Ma-condo, driven by the move into and challenges of the Lower Tertiary reservoir. After Macondo, however, there was rushed incentive to bring in bigger rigs with newer equipment, she says. “They are higher spec—it’s not so much about them being ultradeep, but the capability of adding a second BOP (blowout preventer) and higher crane capacity.”

Paul Hillegeist, Quest Offshore president and co-founder, dubs the new builds Lamborghinis. “Operators want the latest and greatest not only for safety, but for efficiencies. They feel they need the best of the best for these challenging $150-million wells.”

These new rigs with expanded capabilities are leading to higher costs. The average day rate of rigs working in the Gulf presently is $491,000. “That’s more than anywhere else in the world,” says Cook. “We’re seeing leading-edge day rates over $600,000.”

Four operators now account for over half of the rig fleet, according to Quest Offshore: BP Plc, Shell Oil, Chevron and Anadarko Petroleum. Additional operators with rig contracts include two supermajors, two national oil companies and six independents.

New, deeper frontier

Houston-based Cobalt International Energy Inc. in November celebrated its first operated discovery in the deepwater Gulf at North Platte #1, a prospect targeting the so-called Inboard Lower Tertiary trend on Garden Banks Block

959. The prospect, located in 4,400 feet of water and drilled to a total depth of 34,500 feet, has a marquee gross resource potential of some 400- to 800 million BOE with more than 2 billion BOE of gross potential in Cobalt’s offsetting inventory.

“It is a large and significant opportunity,” says James Painter, Cobalt executive vice presi- dent, Gulf of Mexico. The net pay is 350 feet. “Most majors would be happy to have that large of a discovery.”

Started in 2005 with private-equity backing, the now $10-billion publically traded Cobalt was formed with such whale-size prospects in mind. The founders, veterans of international-focused majors, homed in on the 2006-2008 federal lease sales for prospects that would “make the needle move for a major,” as many prime leases were expiring en masse.

“The leases were turning and available, and you could put together large positions.” The team has since compiled 245 deepwater blocks, 75% operated, Painter says.

The company, with deepwater prospects in West Africa as well, put its sights on the emerging Inboard Lower Tertiary trend, a deep subsurface formation under a thicker salt cap than the Outboard portion of the formation. The advent of digital seismic processing brought the rock into focus.

“The trends we’re looking at now are beneath two to four miles of salt. The imaging was not there to visualize it previously,” says Painter. “All of a sudden, you were able to see the structures and that the basins were deeper.”

And they liked what they saw—a higher rock quality than in the existing Outboard producers and high-quality oil and gas. “Having that confirmed at North Platte was important to us,” Painter says. Cobalt holds a 60% interest with partner Total E&P USA Inc. holding the remainder.

The North Platte discovery, however, experienced a two-year delay, as the rig was dropping anchor when the drilling moratorium following the Macondo tragedy was implemented. Cobalt released the rig as it was contracted for a single project, and spent the interim re-studying seismic and high-grading its vast portfolio of prospects.

“We stockpiled prospects,” Painter says. When its new-build Ensco 8503 rig came out of the yard before drilling had resumed, Cobalt contracted it to French Guiana for six months. Now the 8503 is drilling exclusively for Cobalt.

To date, Cobalt reports no production in the Gulf of Mexico or in West Africa. First production is expected from the Anadarko-operated Heidelberg project in 2016, in which Cobalt is a 9.375% partner, and Shenandoah, also operated by Anadarko with Cobalt in at 20%, projected to potentially come online as early as 2017.

Going forward, the impetus is on operated discoveries. “Not only do we have the discovery at North Platte, but we have four or five other opportunities in that area,” says Painter. “It’s a core area now that we’ve proven the Inboard Lower Tertiary works, and that this structure has oil in it.”

With one rig, Cobalt will follow North Platte in 2013 with the Ardennes prospect, forecast to spud in February, targeting both Inboard Lower Tertiary and Miocene with a 500-million-barrel unrisked potential, then the Aegean prospect, a three-way structural closure in Keathley Canyon 163 also aimed at the Inboard Lower Tertiary. “We’re circling the area with our drilling the remainder of the year.”

These wells cost between $170 million and $200 million gross, and take about six months to drill at depths approaching 36,000 feet. Between the Gulf of Mexico and Africa, Cobalt expects to spend $750- to $900 million in 2013. Eleven additional operated Gulf prospects await in 2014-2016. Depending on results, a second rig could be contracted for appraisal work, likely to begin in 2014.

Anticipation grows at Cobalt, as the next 18 months will be the most exciting in the company’s history, Painter says. “We’ve got a group of wells to be drilled that any major would love to have two or three of, yet we’re going to drill seven or eight between the Gulf of Mexico and Africa. It’s what we built Cobalt for—we’ve had success, but 2013 should be a banner year.”

Mission to operate

The world’s largest offshore operator by production, Statoil SA has identified North America as its growth engine, with the deepwater Gulf of Mexico the foundation of a portfolio including onshore U.S. shale plays and Canadian oil-sands and offshore assets. Having made its entry into the Gulf just eight short years ago, the company today participates in half of the top 10 deepwater developments: Tahiti, Caesar Tonga, Jack, St. Malo and Big Foot. Now it wants to operate.

“The one thing we’re missing is the operated development,” says Jason Nye, Statoil senior vice president of U.S. offshore. “We’re working toward that and have built a strong team to prepare for that.”

With 40 years of international offshore experience and as a veteran of the Norwegian Continental Shelf, Statoil is looking to a Paleogene prospect known as Logan to be its first operated field. Located in the far southwestern corner of Walker Ridge, Logan is projected to hold 1- to 2 billion barrels of oil in place. An appraisal well will be drilled in first-quarter 2013.

If successful, Logan will be fast tracked to beat a 2015 lease expiry. “We’re excited because it’s our first operated development. We’ve done a lot of front-end loading in anticipation of this appraisal well being successful,” says Nye.

Heretofore, Statoil has built its presence via nonoperated positions. Gulf of Mexico production stands at 32,000 barrels of oil per day, down from 50,000 following a 2012 sale. Most of that comes out of a 25% interest in the Chevron-operated Tahiti Field, “a fantastic field” that has produced a gross 100 million barrels in 33 months, and Caesar Tonga (23.55%), which came online in 2012.

Three sanctioned projects—the combined Jack/St. Malo fields, and Big Foot, all Chevron operated—are coming online in 2014. Julia and Heidelberg are scheduled to be on production in 2016.

Statoil anticipates leveraging its technological lessons learned offshore Norway to the deepwater Gulf. In particular, the Paleogene play (also called the Lower Tertiary or Wilcox) poses geological challenges in that it tends to be deeper, less permeable and contains dead oil void of gas, creating lifting challenges.

“We’re actually sanctioning these projects with recovery factors less than 10%,” says Nye, compared with Miocene recoveries of 40%. “There is little natural drive.” Using techniques such as water or gas injection, and multiphase pumps on the seabed, “we think we can significantly increase recovery factors in these emerging Paleogene reservoirs to north of 20%, essentially doubling recovery.”

He points to Jack/St. Malo, estimated to contain 5 billion barrels in place. “If you take that from 10% to 20%, you just added 500 million barrels. That significantly improves the economics and commerciality of these reservoirs. Developing the technology is something we’re quite good at, and is money well spent. Half a billion barrels tends to be quite valuable.”

The Miocene and other plays can benefit as well, he says. The Tahiti development is currently being water injected with 50,000 barrels of water per day, the first Gulf of Mexico field to see enhanced recovery techniques applied. “Our view is we’re leaving a lot of resources behind.” Even with added costs, “both here in the Gulf of Mexico and back in Norway, these tend to be very robust projects.”

Logan, if sanctioned, is likely to be developed from the outset to apply gas injection as a second-phase development.

An emerging play that has captured Statoil’s attention is the Norphlet. An extension of the onshore play by the same name, Statoil has acquired 50 deepwater blocks on the eastern edge of the Central Gulf. “If we’re right, it could be quite large.” The Demon Star exploration well is scheduled to drill in the next two years.

Statoil’s mission, he says, is to be a leading Gulf operator with targeted production of more than 120,000 barrels a day by the end of the decade, perhaps much higher. The company is directing more than $10 billion capex here to reach that goal.

Two sixth-generation rigs are presently under long-term contract, though sharing time. The TransOcean Discoverer Americas just finished drilling Candy Bars, a Statoil-operated, Miocene discovery well, but it is being deployed to Africa for a four-well project. The Maersk Developer is returning from another operator to drill the Logan appraisal, and two drill-ready prospects picked up in the most recent lease sale, Thorvald and Martin.

“We’ll be rig short real quick with just a little exploration success. We’ll need a third rig or bring back Discoverer Americas for development drilling.”

Statoil ranks as the sixth-largest leaseholder in the deepwater Gulf with $10 billion invested to date. “We’ve built up a healthy portfolio,” says Nye. “Our path to operated development is through the drillbit. We plan to be here for the long haul.”

Whether development or exploratory drilling, Miocene or Lower Tertiary targeted, operators and capex are washing into the deepwater Gulf of Mexico.

“The U.S. Gulf of Mexico is at a pivotal period in its history,” says Quest Offshore’s Hillegeist. “The new order post-Macondo is projected to see meaningfully larger capital projects led by major oil companies’ appetites for higher impact reserves.” Additionally, he says, “expect action from a few select, highly focused large independents that have significant leverage seeking to expand proven recoverable reserves through expanded infrastructure investments in the region.

“We affirm sight of a rising wave—get ready.”