The Cana Woodford takes center stage for central Oklahoma liquids plays, but the SCOOP, Hunton and Caney are vying for the spotlight as well.

In an age of liquids-rich hydrocarbon love, plays such as the Granite Wash and Mississippi Lime carry the limelight for the Sooner State. But at the heart of Oklahoma, where gas once reigned, operators are now discovering new liquids targets. And while the gas liquids in the western Granite Wash have suffered severe pricing differentials over the past year, and the northern Miss Lime faces challenges in consistency, the unheralded liquids plays in the middle are looking pretty darn good.

The Cana Woodford play tops the bill. While the Woodford shale is ubiquitous across much of Oklahoma, and is best known as a lean gas producer in the Arkoma Basin in the southeastern quadrant of the state, the Woodford in the Anadarko Basin is decidedly wet.

Devon Energy Corp. discovered this in 2010 and made it a company focus after selling down its international and Gulf of Mexico holdings to concentrate on US onshore unconventional plays. At year-end 2012, Devon had drilled 164 wells and booked 427 million barrels of oil equivalent (BOE) of proved reserves here.

The company continues to push the play eastward, where thermal maturities yield more oil. Other name players such as Cimarex Energy Co., Newfield Exploration Co. and QEP Resources Inc. are active in the play.

North of Cana, Devon is also amassing resources to chase its newly revealed Woodford oil play, a region congruent with its Mississippi Lime position. Further to the south of the central Cana, Newfield, Continental Resources Inc. and Marathon Oil Corp. are opening a new oil play known by some as the SCOOP.

And true to the best hydrocarbon basins, Oklahoma hosts multilayered stacked-pay zones, which have not gone ignored in the modern-day quest for oil. In the central region, Gastar Exploration Ltd. and a collection of private operators have hit paydirt in the Hunton play. Far south-central, XTO Energy and BNK Petroleum like results in the Caney shale.

Building on Cana liquids

While the Cana Woodford shale doesn't exude the same sex appeal as, say, the Eagle Ford or Utica shales, Devon Energy is quick to point out that the Cana is one of the most economic shale plays in North America. Devon, too, is the largest leaseholder in the play, with 255,000 acres, a twofold increase in two years. Of those, 204,000 are considered “wet.” That is understood to mean gas liquids, even condensate, yet the Cana is giving up decidedly oily yields as operators further test it to the east and south.

“As far as shale plays—especially in this commodity price environment—the Cana has a lot of opportunity,” says Bret Jameson, Devon vice president of the Anadarko business unit. “We like the results we're getting, and we see it as a driver for years to come.”

For Devon, based in Oklahoma City, the Cana falls in line behind its prolific Barnett program, and ahead of its Canadian oil-sands and Permian Basin programs, based on proven reserves. With 10 rigs running, Devon is in full development mode.

The Cana is named for Canadian County in west-central Oklahoma where the first unconventional Anadarko Basin Woodford well was drilled by Devon in 2007. The hydrocarbon window trends on a diagonal from northwest to southeast about 100 miles long and 25 miles wide, with the oil and liquids band splicing through Dewey, Blaine, Custer and Canadian counties. The basin tends gassy and deeper to the southwest, with more liquids and shallower targets to the northeast.

“You don't hear a lot about it because we've captured the heart of the Cana,” says Jameson.

The company is 100% pad drilling, with two to three wells per pad, and has been able to drop two rigs due to efficiencies and maintain the same pace to drill 150 wells this year. It has some 5,000 identified Cana Woodford locations at 70-acre spacing, 3,000 in the liquids-rich zones. Days to drill now average 20 to 30, half of its earlier program. High pressures of 8,000 psi in some areas present operational challenges, but bit design and mud programs have overcome that.

A Devon Cana type curve expects in excess of 5 million cubic feet equivalent per day initial IP, 9.6 billion cubic feet equivalent (Bcfe) on average estimated ultimate recovery (EUR), or 1.4 million barrels of oil equivalent (BOE), at a cost of some $8 million. “We're beating that on a lot of wells,” Jameson says.

Second-quarter production averaged 322 million cubic feet equivalent (MMcfe) per day, 40% liquids.

Devon takes care of itself when it comes to gas-liquids processing. The company has its own gathering system and processing plant with a capacity of 350 MMcf per day, with volumes delivered to Mont Belvieu.

Devon has tested a handful of double-long laterals in the Cana, but with vertical depths from 10,000 to 15,000 feet in some places, “long laterals are a little more challenging technically in the deeper sections.” One cool new technology to amp efficiency: The company is experimenting with placing fiber optics in the wellbore to measure pressure and temperature data in real time “that allows you to understand the contribution along the lateral. Are some perfs better than others?”

Not blind to softened gas-liquids pricing, Devon is pushing its rigs to the east, where economics are richer. “Obviously, NGLs (natural gas liquids) are a challenge,” says Jameson, “so we're focusing more on the higher condensate yield areas.” Here, the rich gas gets richer, over 1300 Btu, which yields some 160 barrels of gas liquids per MMcf. Better, some wells are even producing 230 barrels of oil per day per MMcf. “It doesn't go exclusively to oil, but it's pretty high in liquids,” he says.

Speaking of oil, Devon is enthused about its newly debuted Woodford oil play, essentially underlying its existing Mississippi Lime program in north-central Oklahoma. With 400,000 prospective acres, chief operating officer Dave Hager said some 100,000 have already been de-risked with 29 wells drilled to date across Logan, Payne and Pawnee counties. In a recent conference call, he highlighted 10 wells that averaged 840 BOE per day initial production, and 500 BOE per day after 30 days.

“We are excited about the Woodford potential,” he said of this northern extension. Comparing it to the Mississippi Lime, he said the Woodford has the advantage in being a shale with resource-play characteristics. “The Wood-

ford is less geologically complex, and therefore should have a much higher drillability factor and deliver more consistent results than conventional formations.”

Oil represents 80% of the flow at initial production, although estimated ultimate recoveries (EURs) are expected to include one-third gas with one-third NGLs. He expects ultimate recoveries to yield 350,000 BOE per well, at a cost of just $3 million.

The Woodford is much shallower in this neck of the woods, just 7,000 to 8,000 feet subsurface. “The Woodford's ease of drilling also allowed us to drill and complete our first 10,000-foot lateral in the trend,” said Hager. The McNeill 6/7H was brought online in the second quarter with an average 30-day IP rate of nearly 700 BOE per day.

Just the 100,000 derisked acres represents 1,000 risked, undrilled locations.

Fifteen rigs dedicated to both the Mississippi Lime and Woodford oil position will ply the play through 2013, but as Woodford holds Mississippian too, “we'll focus our second-half activity on drilling Woodford wells,” Hager said.

“These plays will provide the next leg of large-scale, highly economic oil growth for Devon.”

Driving value to the south

Staying ahead of retreating natural gas prices, in 2010 Newfield Exploration Co. began a focused leasing program in the liquids-laden Anadarko Cana Woodford play, transferring expertise from its dry-gas Arkoma Woodford program. And as Arkoma Basin activity was idled, in three years' time, the company, based in The Woodlands, Texas, has built a 230,000-acre position from scratch and is now in full development mode in portions.

“The Cana has become one of the industry's most active areas,” Newfield chief operating officer and executive vice president Gary Packer said in the company's most recent conference call. “The rates of return on these wells exceed 50% today and are among the highest in the company. We found a great play in the Cana Woodford.”

By year-end, Newfield projects it will produce 27,000 BOE per day from the play, making it the company's largest-producing asset. It loves the program so much it now has seven rigs working the play, one more than projected.

Newfield's Cana holdings follow a trend from Kingfisher County down through Stephens, west and south of Oklahoma City, but it focuses its activity in two regions. The South Cana project with 28,000 acres spans Grady, Stephens and Garvin counties. The North Cana project straddles Canadian and Kingfisher counties.

Occupying six of the rigs, the South Cana project is in full development mode, says New-field vice president, Midcontinent, Clay Gaspar. “We found a lot of success in the south. There is a spectrum of opportunities east to west, where we're drilling for oil, condensate and wet gas wells in that 25-mile band.”

While the Woodford formation averages 300 feet thick here, the vertical depth plunges east to west, as does the thermal maturity. To the east, oil dominates the production mix at 50%, and another 25% gas liquids. Westward, gas liquids make up 50% of the stream.

In its South Cana region, Newfield logs 30 producing wells with average IP rates of 1,475 BOE per day, 36% oil on average. These feature 30-day rates of 1,069 BOE, and even reported 90-day rates of 783 BOE on average. Newfield highlights its 8,000-foot-lateral Boles 1H-14X as best-in-class in this area, producing 1,900 and 1,460 BOE per day at IP and 30 days, respectively (57% oil).

“We're looking to drive the value in the south,” he says.

The Boles represents a new breed of New-field wells featuring longer laterals up to 10,000 feet. “We're seeing for 1.3 times the cost, we're getting 1.8 times the benefit,” Gaspar says, noting a 20% decrease in per-lateral-foot costs. “When you're dealing with 14,000 feet vertical depth, it's a lot of money invested in that vertical portion of the well.”

The technical limit, however, is about 25,000 feet measured depth, encountered on the western edge of the play. On the eastern side, where vertical depths are 8,000 to 10,000 feet, “we're drilling 10,000 footers almost exclusively.” Even adding in the longer laterals, days-to-drill have remained steady at 48 days.

Flashy IPs are not the goal, though, Gaspar emphasizes. “We do a 'slow-back,'” he explains, “which is a controlled flowback technique.” Newfield believes that managing the reservoir drawdown leads to improved overall performance, higher returns and higher EURs. “So our wells come on a little flatter, but parallel the type curve in about 100 days. We're getting better EURs and higher liquids content. The proof is in the results.”

Newfield's type curve for a South Cana long-lateral oil well costs up to $13 million for 1.1 million barrels equivalent, a 50% return.

The North Cana project, with a focus on 19,000 acres and one rig, is more oily and exploratory. Its recent Brueggen well in Canadian County had initial production of 1,000 barrels equivalent, 80% oil, and averaged more than 700 barrels over its first 100 days. The company recently bolted on an additional 70,000 undeveloped acres in the proximity of this area.

Allen Donaldson, Newfield corporate exploration manager, says the company looked at the oil window more aggressively than other companies.

“We drilled our first well in the middle of that fairway with good success. It's just a matter of pushing the envelope there,” he says. “We felt comfortable that we could get oil out of these types of rocks, and that's why we pushed eastward. It's not as easy as our wet-gas piece, but we're finding great success with our first assessment well.”

Newfield models a 40%-plus return on its north oil project, at a cost of $10 million per well for a recovery of approximately 800,000 barrels.

Gaspar adds, “It's less mature from our understanding, but we're excited about it.”

The central area through Cleveland and northern Grady counties remains speculative, with Newfield participating with industry partners in multiple wells to prove the play.

“We have a large acreage position in the central area that could provide significant inventory expansion,” Gaspar says. “We're encouraged by the early results we're seeing. I would expect in 2014 we would start to see more activity there.”

Newfield budgeted $500 million for Cana Woodford in 2013, representing 25% of total company capex. It has identified 1,500 potential locations, before the north oil bolt-on.

“That's quite a few swings at the plate,” says Gaspar, “and there is substantial upside beyond that. We're looking forward to exploiting that.”

SCOOP-ing oil

What Newfield calls its South Cana region, Continental Resources has dubbed the SCOOP, or South Central Oklahoma Oil Province. Here, in Grady, Stephens, McClain and Carter counties, in what Continental has deemed the epicenter of Oklahoma oil, some 3.2 billion barrels have been produced in the last century from legacy fields Sho-Vel-Tum, Golden Trend, Knox and Healdton, with 70 billion remaining.

The SCOOP is heir-apparent to Continental's industry-leading Bakken play, quickly taking second billing in the Oklahoma City company's analyst discussions. “We're excited about this emerging play,” Continental president and chief operating officer Winston Bott said in a conference call earlier this year. With returns of 40% to 80%, “the economics compete very favorably with the Bakken.”

Continental rapidly amassed 277,000 acres in a 100-mile swath across the southeastern tip of the Anadarko Basin, where the Woodford shale can be as thick as 400 feet. Like Newfield's experience, Continental has identified condensate and oil commodity windows. It has focused its early efforts in a 40-mile condensate band on the upper side of the play as it holds by production its position.

“We've generated very strong production growth in SCOOP this year,” Bott said in August. “We're encouraged with the results and feel confident we now have confirmed a productive footprint of approximately 40 miles northwest to southeast.”

In this area, Continental has participated in 93 completions through second-quarter 2013, with production exceeding 17,550 BOE per day. During the quarter, condensate wells averaged 1,490 BOE per day IP (29% oil); oil wells averaged 1,460 BOE per day (55% oil). One, the Vanarkel 1-15H, on a 640-acre spacing unit, flowed 2,045 BOE at IP (44% oil).

Continental models condensate fairway type curves at 1.2 million BOE EUR (61% liquids). For the oil fairway, it estimates 626,000 barrels equivalent of oil in place (75% liquids). Wells with a one-mile lateral cost approximately $8.5 million.

“The economics compete very favorably with the Bakken,” said Bott. “The results are quite repeatable within a given fairway.”

The upper 40-mile focus was driven by leasehold expirations. Now, the company is targeting another 40-mile region to the south. “We're just as excited about what we have in front of us as we are about what we've already discovered,” said Bott. “We feel we can take this another 40 miles southwest.”

Continental recently drilled its first cross-unit lateral, extending 9,377 feet for a total measured depth of 25,100 feet, more than doubling the lateral length of its standard SCOOP wells for $13.8 million. The Singer 1-18-7XH in Grady County produced 1,915 BOE (37%) initial production. “Initial expectations for cross-unit wells could double production and proved reserves with only an incremental increase of 55% to 60% in cost,” the company reported in its second-quarter results.

The company expects to spend approximately $540 million in the play in 2013, 15% of its overall budget. It is ramping up with two additional rigs in the play for 12 total, to target what it sees as 10,000 to 20,000 drilling locations. Using average EURs, “that turns into between 4.5- and 7 billion worth of unrisked resource potential in our inventory,” said Bott.

“We're excited about the outlook for this emerging play. It's got a lot of running room and we think this is repeatable.”

New Hunton

Consider the beauty of this deal: In June, Gastar Exploration Ltd. acquired 157,000 net acres with producing reserves in the north-central Oklahoma Cana Woodford shale and Hunton limestone plays from Chesapeake Energy Corp. for $69 million. In August, Gastar flipped 76,000 of the acquired Cana Woodford acres to Newfield Exploration for $62 million. Factoring in another $12 million pocketed from a joint-venture partner election to participate for a net 12,800 Hunton acres, Gastar netted 68,200 new acres—free. Actually, better.

“We put $4 million in the bank, bought close to $30 million of proved developed producing reserves, and got 68,000 acres in the core of our play,” says Gastar president and chief executive Russ Porter. “It was just one of those transactions that worked out very well.”

That is if you value the Hunton, and Gastar does. It now features a total portfolio of 96,000 net acres centered around the intersection of Kingfisher, Logan and Garfield counties.

But Porter is quick to point out this is not the traditional Hunton dewatering play some equate to the Hunton. Gastar is targeting an updip zone where the Hunton pinches out into the Woodford above, and where water production is less of a factor.

Porter explains, “We're going into a reservoir that's been drilled vertically for decades and producing oil that was not originally accessed with vertical wells. Those vertical wells mostly produced porosity in the upper Hunton. The middle and lower Hunton are mostly a fractured play, and we're drilling horizontal wells to intersect as many of those fractures as possible in the wellbore, and going in with multistage completions.”

To date, Gastar has participated 50-50 in five nonoperated wells on a 35,000-acre area of mutual interest (AMI) with a private operator. The second is the most illustrative of the potential. The Mid-Con 2H, put on production in February, peaked at 1,100 barrels of oil and 2 MMcf of gas. In August, it was producing 771 BOE per day, 63% oil, and had cummulatively produced 154,000 BOE. A third-party report estimated ultimate recovery of 740,000 barrels.

The third and fourth wells experienced mechanical challenges, specifically problems with gas-lift compression, and frac-sand flowback into the wellbore. Oil cuts today of 70 to 100 barrels a day are expected to improve once the mechanical issues are resolved. The Hunton wells also typically take two to six weeks to reach peak production while fracture-stimulation fluids are recovered. A fifth well is waiting on completion, and a sixth is drilling.

Gastar looks beyond these wells to model its type curve. Some 50 modern wells have been drilled in the play in the last 18 months, another 20 by its partner outside the AMI. The only hitch is results are held close to vest.

“We're the only public company in the play,” Porter points out. “The private companies are not announcing results, so there are no other sources of information for the capital markets to judge this play other than our announcements.”

The partner's last seven non-AMI wells averaged 645 BOE per day peak rate, with a 436 EUR each. At 65% liquids and 35% gas with an average well cost of $5.2 million, Porter projects a return of 65%. “We're in the play because we like the economics,” he says.

In September, Gastar deployed its first operated rig with the intent to drill three wells by year-end. “Once we start operating our own wells, and have four to five wells that we've operated and where we've chosen all the locations and done all the work, then I think we—and the capital markets—will have a good feel for the play.”

Plans for 2014 include 16 wells, eight operated. Gastar identifies 275 drilling locations using 320-acre spacing across its Hunton oil play with exposure to 100 million barrels of resource, contrasted to its current 42 million BOE resource base.

“We've got plenty to keep us busy for a while,” says Porter. “We could triple our reserves with successful development. And with it being 70% liquids, that will have a big impact on the company's profile and value going forward.”

Not to mention Woodford prospectivity, which he projects across a third of Gastar's position. The company is currently participating with a small interest in a Woodford well, serendipity of forced pooling. “We'll be able to get all the data and knowledge of the formation, with very small financial exposure,” he says.

“We're early in the game, with a large position that we got at extremely low cost. Industry activity around us is increasing rapidly. We're very, very optimistic about this play.”

Subsequent to Oil and Gas Investor's interview with Porter, Gastar acquired an additional 24,000 held-by-production acres in Kingfisher, Logan, Oklahoma and Canadian counties for $187 million, all adjacent to current holdings.

“In addition to the existing reserves and production included in this package, we expect significant, low-cost, low-risk upside potential from the development of the upper Hunton limestone (Bois d'Arc formation), where proved undeveloped reserves booked to date cover less than 30% of the total acreage we are acquiring,” Porter said in the announcement.

“We also see the potential for substantial, low-risk high-return drilling opportunities in

the deeper lower Hunton limestone (Chimney Hill formation) that has not yet been developed on this property. We believe the Chimney Hill resource could be proved up with limited drilling capital, given the recent nearby offsetting activity by other operators that is rapidly de-risking the play.”

Gastar has identified 62 Bois d'Arc PUD locations, plus an additional 44 Chimney Hill probable drilling locations just within a 7,000-acre northern portion of the block that has been the site of recent activity by the seller. Beyond this 7,000-acre initial development area, the company catalogs an additional 60 Bois d'Arc and 40 Chimney Hill well locations that could be developed in the southern portion of the HBP acreage, he said.

“The Upper Hunton wells can be produced open-hole and drilled at a cost of approximately $2.3 million each, generating an estimated internal rate of return greater than 50%. We will also evaluate the use of multi-lateral wellbores in this formation to further enhance the economics. The lower Hunton wells cost an estimated $4.5 million each, with internal rates of return projected to exceed 60%.”

Down in the Ardmore

The Ardmore Basin in deep south-central Oklahoma is like the dot on an exclamation point to the Anadarko Basin, sitting just below to the southeast. It cuts diagonally through Carter, Johnston and Marshall counties. The Woodford shale is present here as well, where it measures up to 500 feet in thickness. Better, the thermal maturity is in the oil window, with resistivity factors greater than 2% in the deeper parts of the basin, according to the Oklahoma Geologic Survey.

The low-key Ardmore is the sparkle in one major's eye.

XTO Energy, the unconventional-resource arm of Irving, Texas-based ExxonMobil Corp., holds most of the acreage in the Ardmore Basin with more than 280,000. This comes after vacuuming up the positions of most all other smaller operators such as Wagner & Brown, Antero Resources, Walter Oil & Gas, as well as Chesapeake Energy. The global energy giant has 12 rigs running in the play, elevating the Ardmore Basin to the top of its unconventional portfolio. That portfolio includes celebrity status liquids-rich plays in the Bakken shale and Permian Basin.

“This is our most active unconventional play,” ExxonMobil chief executive Rex Tiller-son touted in a March analyst call. Delineation of the Woodford shale completed in 2012, including space testing and pad development. Additionally, the company is testing the overlying Caney shale in the Ardmore Basin and prospects in the Marietta Basin to the southwest.

“The results of both drilling and acquisition additions have increased the Ardmore's total resource estimate to more than 1.5 billion oil

equivalent barrels,” Tillerson said. “This has the potential to generate more than 150,000 oil equivalent barrels per day, and we continue to evaluate further upside in the Woodford and other formations.”

Production at the end of the second quarter was 31,000 barrels equivalent per day. According to a report by Fortune magazine in April, Exxon expected to drill 130 wells in the region in 2013, with typical laterals about 5,000 feet. The company reports about half of its total 11,000 US unconventional drill locations are in the Ardmore region.

Which brings us to BNK Petroleum Inc. The Camarillo, Calif.-based explorer is best known for its play for shale gas in Poland, but its revenues are being generated in the Ardmore, most recently from the Woodford. In April, BNK traded that cash flow from 1,800 barrels a day for $147 million in a sale to XTO. The deal included 12,500 contiguous acres and 45 horizontal Woodford wells in Carter and Johnston counties, the last of the active operators in the region.

“It was just us and them,” says Wolf Regener, BNK president and chief executive officer. “It's hard to stay in the game at $18 netbacks when you have somebody like XTO that wants to down space at 10 wells per section.”

Regener reports Woodford wells in the later stages of BNK's drilling program were IP'ing at 900 to 1,200 BOE per day, yielding 20% oil, 40% gas liquids (50% ethane, 25% propane), the remainder lean gas. Here, the Woodford vertical depth ranges from 6,000 to 12,000 feet to the top of the formation, with average thickness of 340 feet. His proved plus probable EUR estimate for the sold acreage amounted to 36 million BOE.

But BNK clawed back the rights to two formations, the Caney shale and the upper portion of the Sycamore lime, both overlying the Woodford trend, where it now holds 13,400 acres including its original footprint.

“When Exxon started talking about this area in their quarterly reports, we figured it was something they believed in and that we needed to pay attention to. Their actions are showing us they believe in it as well.”

Exxon has drilled four wells in the zone, notably the Cook 3-6H31. This well produced 580 BOE per day on a three-week rate, and 416 BOE in its third month.

The Caney potential was not new to BNK, however, whose geologist had alerted management years prior that the shale looked as good as any other emerging opportunity they were looking at here or abroad, and that it should be tested. “It needed a shot,” he says. BNK did that in a vertical Woodford well recompletion into the Caney. “It shocked us when it came back 100% oil, given it's just 350 feet above the gassy Woodford.”

BNK participated in several Arkoma Basin Caney shale wells several years past, but high clay content inhibited productivity, and the program was abandoned. Caney clay content in the Ardmore Basin, though, is much lower at 37%. BNK drilled its first horizontal test in 2012, landing the lateral in three zones: the upper Sycamore lime, the limestone-stringer-laced transition (or “T”) zone, and the lower Caney. By isolating the stages, tests showed the transition zone to be the most productive. “That's where we've targeted three additional wells since then.” The Caney/Sycamore combination is 350 feet thick, of which 70 feet is transition zone.

The Dunn 2-2H, BNK's second well, IP'd at 550 BOE per day and is still cleaning up. A third is flowing back frac fluids, and a fourth is drilling. A fifth was to spud in early September. Lateral lengths are capped at 5,000 feet due to pre-existing 640-acre units. Well costs run about $8.5 million currently.

“We're hoping to get wells with an IP of 450 barrels of oil per day, which is about a 140% rate of return for 600,000 barrels of oil. We think that's quite doable,” says Regener, noting early Ardmore Woodford wells produced below that threshold. “We need a breakeven of about 150 barrels per day and 180,000 barrels EUR, but if we can get 140% return, I'm a happy camper.”

BNK is currently running one rig, but could ramp to two next year. Regener anticipates 160 drill sites assuming 80-acre spacing, currently being tested by XTO nearby. “If these wells have good production rates, you'll see us get really active,” he says. Capex targeted to the basin will be in the $45- to $60 million range, assuming continued success, representing about 85% of the company total.

“From a standalone basis, we would have leased this trend on our own to try it, but it just so happens it was behind pipe and held by production from the Woodford,” says Regener. “Being able to monetize the Woodford and roll that cash into the Caney shale was the biggest lift we could get for ourselves,” he says.

“It's hopefully going to be a very large value creator for BNK. Considering where we're trading—about $180 million in market cap—if we can get to 500,000 to 600,000 barrels of oil per well and downspace, that's a big prize. It looks like it is going the right way.”

Note: Select conference call data sourced from seekingalpha.com.