It’s a reality of life that we tend to general¬ize to save time. We read that, after years of growth, U.S. production is in decline, as mainly unconventional producers modulate short-cycle output lower (and higher) in line with a given price signal. Few focus on the Gulf of Mexico, assuming an investment deci¬sion on long lead-time production is tough to make amidst ongoing oil price uncertainty.

But activity in the Gulf is not necessarily flagging. A tight group of dedicated players— both public and private-equity-backed compa¬nies—push forward with long-term plans for exploration and, in particular, development, of reserves that can be tied back to host facilities. While some production growth reflects invest¬ments made at higher oil prices, there is new activity boosted by drastically lower costs.

How do production numbers for the Gulf compare to those of onshore?

U.S. Lower 48 production, including the Gulf, has been on a downward slide since peaking in May 2015, falling from about 9 million barrels of oil per day (MMbbl/d) to just under 8.2 MMbbl/d in June of this year, according to the U.S. Energy Information Administration (EIA). This represents a decline of roughly 9%.

Production from the Gulf, by contrast, has been able to register gains. Compared to output of about 1.43 MMbbl/d in May of last year, production was up almost 11% to 1.59 MMbbl/d this May, the most recent month for which production data for the Gulf was available.

Moreover, a February 2016 study by the EIA called for Gulf production to average 1.63 MMbbl/d this year and to “increase to record high levels in 2017, even as oil prices remain low.” The EIA projected Gulf output would average 1.79 MMbbl/d in 2017 and reach 1.91 MMbbl/d in December of next year.

Growth in Gulf output has involved both public and private entities, in many cases work¬ing in tandem.

In the public arena, Noble Energy Inc. com¬menced production late last year at its Big Bend and Dantzler fields. Located in Mississippi Can¬yon 698 and 782, respectively, the fields produce by way of tiebacks to the third-party Thunder Hawk facility. Earlier this year, Noble also saw the start-up of its Gunflint Field in Mississippi Canyon 948. Production from the three fields, net to Noble, was estimated at 25,000 barrels of oil equivalent per day (boe/d).

With a long history of success in the Gulf, publicly traded Anadarko Petroleum Corp. reported its first production at its Heidelberg Field early this year, using a spar of similar design as that of the company’s earlier Lucius Field. Lucius continues to exceed its name¬plate capacity of 80,000 bbl/d, benefiting from “outstanding well deliverability,” according to Anadarko in its second-quarter earnings release. Initial flowback data from the seventh Lucius development well indicated “rates in excess of 15,000 boe/d.”

As part of its Shenandoah appraisal program, Anadarko also announced “promising results,” with its Shenandoah-5 well encountering more than 1,040 net feet of high-quality oil pay.

In addition to developing reserves on a standalone basis, such as with the Heidelberg spar, Anadarko has stated it has 30 or more potential tieback opportunities in the Gulf. Evidently, some of these are able to compete successfully for capital alongside the compa¬ny’s onshore unconventional projects.

“Our Gulf assets provide us with a capi¬tal-efficient value driver,” said Anadarko CEO Al Walker, on the company’s conference call. Pointing to its “outstanding performance in the Gulf” in the quarter, Walker said Anadarko had several competitive advantages, including a successful exploration track record, an “indus¬try-leading” project management capability and “a large, operated infrastructure position.”

But often working together with these pub¬lic E&Ps is a number of private-equity-backed players—a select group of regional specialists who, when appropriate, join forces to share risk and reward.

“We partner a lot more than we compete against one another,” commented one veteran Gulf player.

Venari Resources LLC is one such deepwa¬ter exploration and production company. It is focused on the subsalt play and was one of the first to enter the deepwater Gulf in the wake of the Macondo incident. The company is led by CEO Brian Reinsborough and is backed by pri¬vate equity partners that have raised two lines of equity totaling $2.4 billion.

Venari’s initial $1.125 billion round of private equity came in 2012 with funding from Warburg Pincus LLC, Kelso & Co., Temasek and The Jordan Co. In mid-2014, Venari raised an addi¬tional $1.247 billion of equity commitments, with the existing investor group expanded to include, among others, BlackRock Private Equity Partners and GIC, the sovereign wealth fund of Singapore.

“We’ve drawn down about half of the total $2.4 billion, so we still have a lot of dry powder to execute our plan,” said Reinsborough. “The timing of the second raise was very good, and we’re very happy with the strong investor base we have behind us.”

Venari has focused primarily on Lower Ter¬tiary and Miocene objectives. Recently, in the eastern Gulf, the Norphlet has also been added as an objective.

Earlier in his career while at Nexen, Reins- borough was instrumental in discovering of the Appomattox Field, which is targeting the Nor¬phlet Formation. A final investment decision (FID) to approve developing Appomattox was taken by Nexen and Royal Dutch Shell Plc, the operator, and Nexen last year.

In the central Gulf, Venari’s major successes have been at Shenandoah, where Anadarko is operator, and at its Anchor prospect, operated by Chevron Corp. Morgan Stanley has put the preliminary reserve estimates for the two fields in the range of 400-450 MMbbl apiece, levels which Reinsborough said were within his range of estimates.

“We believe both these fields are signifi¬cant discoveries,” he said. “You can’t pinpoint an exact reserve estimate for a field at this point in time, because it moves around with appraisal drilling.”

The Shenandoah-5 well is not the first well to encounter over 1,000 feet of net pay in the Walker Ridge area. The Shenandoah-2 well, structurally downdip from the discovery well, also found net oil pay “in excess of 1,000 feet.” The most recent well has extended the Shenan¬doah Field farther east. A Shenandoah-6 well to be spud later this year will attempt to find the oil-water contact. The likely timing on an FID to develop of the field is expected to be early 2018.

Initially, Venari held a 10% working interest in Shenandoah. However, another 10% became available as Marathon Oil Corp. made its stra¬tegic decision to leave the Gulf. Anadarko and Venari shared in buying the Marathon stake, with Anadarko’s interest rising from 30% to 33%, while Venari’s interest jumped from 10% to 17%.

“Strategic moves can sometimes create great opportunities,” said Reinsborough. “The timing was just perfect. We believe it to be a very, very attractive deal.”

In a short note published by Tudor, Picker¬ing, Holt & Co., the transaction metrics for the 10% stake acquired by Anadarko/Venari was estimated at roughly $1/boe.

Anchors away

Venari was also able to bump up its working interest in its Anchor prospect, another of its recent exploration successes. The transaction followed the withdrawal of Samson Offshore Anchor LLC, which held a 12.5% work¬ing interest in the project. Venari was able to increase its interest in the northern portion of the prospect from 12.5% to 18.75%, while in the south its interest is 12.5%.

With two wells down, “the appraisal results to date suggest that Anchor could be one of the largest oil accumulations in the Lower Tertiary Wilcox Trend,” said Reinsborough at the time of the discovery late last year. After the discovery well found 690 feet of net oil play in multiple Lower Tertiary Wilcox sands, the downdip side-track appraisal well encountered a similar 694 feet of net oil play, as well as “a hydrocarbon column of at least 1,800 feet in the Lower Ter¬tiary Wilcox reservoirs.”

Results from a third well are close to being fully evaluated, at which time drilling a fourth well will commence immediately, enabling the appraisal process to move ahead quickly. Estimated reserves at Anchor are expected to justify a standalone development. A rule of thumb is that some 200-250 MMboe, at a minimum, is likely needed to develop a Lower Tertiary Wilcox Sand prospect in the deepwa¬ter, according to Reinsborough. After a period of analysis, an FID is projected for late 2018/early 2019.

A strong tieback candidate, in which Venari holds a 40% working interest, is the Coro¬nado prospect. With a 60% working interest, Anadarko is the co-owner of the prospect, which is located just six miles from Shenandoah. An appraisal well is likely to be drilled next year to further assess the potential scope of the Coro¬nado discovery.

What sort of price deck does Venari use for projects whose first production may be several years out?

“All of our projects are long-cycle projects, with Shenandoah scheduled to be the earliest to come on production in 2021,” said Reinsbor¬ough. “We’re not so worried about the price of oil this week or this month. We gauge ourselves on a five-year window on pricing. We’re still very optimistic that the price of oil post-2018 and 2019 will be back in a normalized range at which these projects will be extremely economic.”

For its price outlook, Venari combines over a dozen sources and then takes a “conservative” viewpoint.

On the cost side of the equation, Reinsborough pointed to an oversupply of high-spec deepwater rigs, which can now be contracted in the mid-to-high $200,000/day versus about $500,000/day in 2014. In addition, the cost structure of any proj¬ect is examined “very, very critically right now,” whether by Chevron or by Anadarko, both “top tier operators,” he said.

At Shenandoah, for example, a breakeven level, assuming a minimum required internal rate of return of 10%, is projected “in the low $40s per barrel,” according to Reinsborough. “Shenandoah appears to be a large field, and scale helps quite a bit. The reservoirs are good and the economics are healthy, which in turn reduces breakevens.”

Dollar-cost averaging

Privately held LLOG Exploration Co. LLC is the quintessential American success story in that it has grown from humble beginnings to be a major player in the Gulf. With output running at roughly 72,300 boe/d in the first half of this year, the company ranks as the fourth largest liquids producer in the Gulf, behind three public major oil companies.

As it has grown, LLOG’s funding sources have included a $1.2 billion strategic joint venture struck with private equity sponsor Blackstone in 2012. This has helped fund exploration, appraisal and development projects, primarily related to fields surrounding the Delta House floating pro¬duction system (FPS) that is located in Missis-sippi Canyon 254 in 4,500 feet of water.

While LLOG owns interests in over 100 blocks in the Gulf, Mississippi Canyon is called its “primary leasehold.” A major milestone was when Delta House began producing in April of last year, marking just three years from first discovery to first production. The company continues to pursue “other growth initiatives in our Mississippi Canyon focus area,” said Rick Fowler, vice president, deepwater projects.

As for further financing, “our relationship with Blackstone continues to grow, and we have established a new platform to capture additional opportunities in the current environ¬ment,” said Fowler.

LLOG has been rigorous in its consistency of strategy throughout the recent commodity collapse.

“LLOG takes a long-term view on pricing,” said Fowler. “As a result, our spending stays relatively stable through periods of high or low commodity prices. LLOG continuously operated two deepwater drilling rigs through the downturn, which was our plan prior to the commodity price drop. We are somewhat con¬trarian in that we continue to drill when prices are lower to benefit from ‘dollar cost averag¬ing,’ since more wells can be drilled for the same amount of capital.”

LLOG categorizes some prospects in its inven¬tory as “hub class” (requiring an FPS if success¬ful) and others as “tieback class” (anticipating a tieback to an existing host facility if successful). Drilling tieback prospects near existing infra¬structure operated by LLOG has helped lower reserve thresholds needed for prospects to be economic, according to Fowler.

As an example, Delta House was originally designed to bring three fields online in about three years from discovery, but by the end of this year will be processing production from five fields. Recently, LLOG tied back its Otis Field, noted Fowler, “and we expect additional fields to be tied back to Delta House in the near future.”

In designing facilities for “hub class” pros¬pects, LLOG has made “tremendous use of standardization to great advantage in terms of cost and schedule,” according to Fowler. For example, under an alliance it has with FMC Technologies Inc., LLOG has installed 31 sub¬sea trees that are all the same design, lowering cost and lead times, as well as enhancing reli¬ability and safety.

Elsewhere, LLOG has been innovative, bidding the fabrication yards before complet¬ing its engineering design. “That way,” said Fowler, “we could involve the fabrication yards in the design, so they could tell us how to design the FPS such that it would be easier for them to build. Other operators generally don’t involve the fabrication yards until the design is complete.”

LLOG’s future contains continued growth through the drillbit, according to Fowler, as the company sees “many opportunities in the Gulf that meet our return requirements.”

But what ingredients have made for such a success story in the Gulf—one that can boast a 70% success rate in deepwater exploration?

The LLOG strategy combines four tactics, according to Fowler: 1) acquire large seismic datasets with the most advanced processing; 2) pursue prospects with nearby successful analogs; 3) pursue both hub class and tieback class prospects; and 4) upon success, use stan¬dardized development techniques that result in fast schedule and low cost.

Taking advantage of low costs

Deep Gulf Energy Cos. is a partner with LLOG on several projects, with an interest in five wells that are already producing through the Delta House facility. Heading up the Deep Gulf team is president Richard Clark, formerly executive vice president with Mariner Energy Inc., one of the first independent operators active in the deepwater Gulf.

Deep Gulf is backed by private equity spon¬sor First Reserve Corp. and has invested $1.4 billion in the deepwater Gulf over the last 10 years. Two of the companies formed to facili¬tate this investment, Deep Gulf Energy II and Deep Gulf Energy III (DGE II and DGE III), remain active.

How has the recent downturn influenced Deep Gulf’s activities?

“We slowed down on a couple of projects to improve our liquidity, but we didn’t change our strategy,” said Clark. “We saw the very large reductions in drilling and completion costs, and we wanted to take advantage of the situation by drilling while costs are low and bringing projects online when commodity prices are, hopefully, recovering.”

Clark estimated that the company’s drill¬ing and completion costs have come down by 30%-40%, while subsea construction costs have fallen 25%-30%. With cost reductions of this magnitude, “the economics for our type of projects in the Gulf compare very favorably to the onshore resource plays,” he said.

Deep Gulf’s activities are principally tar¬geting various Miocene objectives, which are then developed using subsea tiebacks, with comparatively lower demands on capital.

“Since we typically are not investing in platforms and export pipelines, our capital requirements are relatively low,” said Clark. “We move quickly such that in most cases we can get a field onstream in less than two years from discovery. We focus on low-risk amplitude plays, so our success rate is high. The Miocene reservoirs we exploit typically produce 7,000-10,000 bbl/d per well.”

How does Deep Gulf view the commodity outlook and its impact on its economics and activity levels?

“Our breakeven levels are well below $50/bbl for all our projects, and that number con¬tinues to improve with reduced finding costs,” said Clark.

With input from First Reserve, Deep Gulf anticipates that crude prices will rise to around $60/bbl in the next two to three years, he said, with $55-$65/bbl being a price range that would trigger a meaningful increase in activity.

In its two active ventures, DGE II and DGE III, Deep Gulf has had several notable dis¬coveries, including Odd Job on Mississippi Canyon 215; South Santa Cruz on Mississippi Canyon 563; and Barataria on Mississippi Canyon 521.

At Odd Job, in which both ventures have an interest, two wells have been drilled. The first is due to come onstream early next year after being tied back to Delta House, and is expected to produce about 10,000 bbl/d. Two additional wells are likely to be drilled at Odd Job over the next two years as capacity becomes available at Delta House.

At Santa Cruz, in DGE III, a single well has been drilled that is expected to come onstream in early 2017. The well is projected to pro¬duce 7,000 bbl/d after being tied back to the third-party Blind Faith facility. A second well exploiting an adjacent fault will be drilled a year after the first comes onstream.

At Barataria, also in DGE III, a single well has been drilled that is expected to come onstream early next year. The well is expected to produce 6,000-8,000 bbl/d and will be tied into the S. Santa Cruz subsea system, connect¬ing it in turn to Blind Faith.

An example of Deep Gulf’s technical capac¬ity is provided by its Kodiak project. The com¬pany bought the project from BP in the wake of an appraisal well’s disappointing results, prompting concern over likely field size. Last year, DG II completed a development well that exploits three of the field’s primary zones. The well currently produces 12,000 bbl/d from two “U” sands, but can remotely add in the “Q” sand if a permit to commingle the zones is approved. This would take production up to 20,000 bbl/d or more.

“Kodiak was a very tough project,” recalled Clark. “The producing reservoirs are subsalt, very deep, with very high pressures and tem¬perature. In fact, the Kodiak well completion is recognized as the highest pressure and tem-perature ‘frack pack’ completion in the Gulf. Because of the CO2 content and high pressure, we had to use corrosion-resistant, alloy-lined flow line material. This was the first appli¬cation of this technology in the Gulf. Our operations team did a great job meeting these technical challenges, and we are very pleased with the early performance of the well.”

Offshore