During its two-day analyst presentation in Baku, Azerbaijan, this past June, international major BP’s top upstream brass spotlighted the large successes that lie ahead after all the dramatic changes they’ve made on the turbulent road since the disas­trous Macondo tragedy. In the past five years, London-based BP has transformed: it sold $75 billion of assets, includ­ing its interest in TNK-BP, cut the global upstream head count by nearly a third, reduced costs and improved safety.

But it’s no longer in defensive mode. BP is facing forward. It has inked new partnerships including with Chevron Corp. in the Gulf of Mexico, Hilcorp Energy Co. in Alaska and Aker S.A. in Norway’s North Sea, and in March, it signed a shale production sharing contract in the Sichuan Basin, China. Because of these initia­tives, the new BP has a tighter focus and a lot of growth ahead, with some 500,000 barrels of oil equivalent per day (boe/d) of new capacity coming onstream around the world by year-end 2017.

One of the biggest changes occurred state­side, when BP Lower 48 was given authority to operate autonomously—and much more like an independent—as it pursues 7.5 billion barrels of oil equivalent (Bboe) of short-cycle resources. These are found in choice plays: the Eagle Ford and Haynesville shales; the Greater Green River, Arkoma and Anadarko basins; the Cotton Valley and Bossier plays in East Texas; and the San Juan Basin’s Mancos Shale and coalbeds.

All told, BP has identified 15,000 horizontal locations on its Lower 48 acreage. The tanta­lizing upside is that these are mostly in areas where BP Lower 48 has drilled very few or no horizontal wells and has not applied modern fracturing techniques. This summer, for example, results are forthcoming from its first trilateral, co-planar horizontal well drilled to the Cleveland Sand in the Anadarko Basin.

Aiming high in this target-rich environment is BP Lower 48 CEO Dave Lawler, who joined two years ago this month. A petroleum engineer who graduated from the Colorado School of Mines, he brings experience from 10 years working at Shell Oil and before that, Conoco and Burl­ington Resources Inc., and most recently SandRidge Energy Inc., where he was executive vice president and COO.

Lawler’s 1,200 employ­ees are combining the best attributes of majors and inde­pendent shale players—and London is noticing. We met with him recently to learn more about this huge domestic E&P company hidden within a mega-major.

“We are now an auton­omous unit with 6 million acres, and we’re drilling and completing wells in a highly innovative way,” Lawler said. “We believe we are as competi­tive as an independent at this point, in terms of development and operating costs. I won’t say we are better, but we have definitely caught up.”

Investor What was behind BP creating this separate unit?

Lawler BP, to its credit, recognized the company was not as competitive in the U.S. onshore market as it wanted to be, so it was internally driven to make a change and become more like an independent. Almost 20% of BP’s resource potential sits within the U.S. Lower 48, so given that position, it was very important that the company deliver strong results.

BP is a clear leader in delivering large-scale international projects and in dealing with foreign governments across the world and is also a clear leader in deepwater development. The one area where it wanted to improve was in unconventional resource development.

Investor You came to BP at such a tough time. What was that like?

Lawler Prices started to decline right after I joined the company. About two years ago during my interview with BP, I asked to see the maps showing the vast acreage position. I was thinking in the back of my mind that the acreage would support about 60 profitable rigs, but commodity prices kept dropping, and we only got up to 15 at the peak. It was kind of disappointing. Not only were we trying to explore and figure out what we had, but we also needed to do it in a continually declin­ing price environment. We will average five operated rigs this year, and at the end of 2015, we had 15.

Investor How do you propose to create value in the Lower 48—you have such a broad canvas. What did you want to do first?

Lawler We elected to take a close look at the assets we had in our portfolio. The company is in some rich basins, but largely they’ve been untested with the latest technology. We have hundreds of vertical wells in place, but we didn’t have many horizontals. For example, in the Greater Green River Basin in Wyoming, our strategy was to drill several horizontal wells with the latest technology. We’ve now done that and are very pleased with the results.

Investor What are your one or two biggest focuses, now that you have a mandate?

Lawler Our vision is to become a premier, market-visible, highly competitive company. By premier, we mean being the safest company, and one of the most capital-effi­cient, while outperforming our peers in cash-flow growth, and adding reserves at a competitive price.

Investor What size and value are we talking about for Lower 48?

Lawler To put the business in perspective in terms of the value opportunity, few people possibly realize that there are independent companies producing around 300 Mboe/d, the same as we do today, that have an enterprise value of roughly $15 billion. What you prob­ably have not seen is that our team has now identified up to 15,000 horizontal wells.

In the Greater Green River Basin, for example, this is how we define it: We have 500,000 net acres, with several thousand vertical wells drilled, but with minimal stimulation of one or two primary intervals. There are six distinct petroleum systems there … yet for decades we just drilled verti­cal wells. Now we have eight horizontals down since September 2015—the first BP horizontal wells drilled in eight years.

Investor What kind of well results have you gotten?

Lawler They are delivering strong returns, with some reaching a 45% IRR after tax. It’s very exciting to see what the team is doing, and it’s getting a lot of attention from London. For example, in Wyoming’s Wamsut­ter Field on the Luman 10-40H, which is a 4,000-foot lateral, the 30-day IP was 1,473 boe/d. That was our first 1,000 boe/d well in the Lower 48 in the company’s history! And we think we have 2,000 horizontal wells to drill in that basin alone.

We’ve turned on an entirely new play in an area that was thought to be an old verti­cal play of mainly gas. This is the story we shared in Baku a few weeks ago.

Investor What about in the San Juan Basin, where you just bought Devon Energy’s storied Northeast Blanco Unit?

Lawler We had not drilled a well there in five years—it was largely idle. But the team got busy in 2015 and drilled four multilaterals in coalbed methane. We drill horizontally for 2,000 or 3,000 feet, then we drill another 2,000- or 3,000-foot lateral in a slightly different direction. We have also drilled a trilateral well. The dual wells cost us about $1.6 million, and bring on 6 billion cubic feet. These are 100%-plus rates of return—and we think we have another 270 horizontal wells to drill. Not to mention a potential 1,600 Mancos Shale locations.

Investor Does this sort of success make BP want to drill shales in the U.K.?

Lawler Our hope is that we can export this technology to many other places around the world. This is another reason why the advancements we’re making are so important.

One other example that speaks to our mission of being competitive is the Wood­ford Shale in the Arkoma Basin. We had not drilled there since 2012. But now, we’ve had a 45% decrease in drilling time, and the well cost has been reduced by 62%. We’ve started to use advanced stimulation techniques, and we’ve increased the EURs by 44% since 2012. This is the very definition of increased efficiency.

Investor To what degree are these improve­ments due to better technology versus lower service costs?

Lawler We think at least two-thirds of these savings are sustainable. If you look at 45% improvement in drilling speed, that’s a signifi­cant portion of the drilling operation.

We have 890 Woodford wells to drill, including the potential of 1P and 2P reserves.

Investor Are you focusing more on oil or natural gas?

Lawler As we make our way through this puzzle, we’re moving away from the whole conversation about unconventional versus conventional, and oil versus gas. We are trying to drill all the saturated intervals avail­able to us, whatever they may be. The Greater Green River is sandstone with liquids; the Woodford is dry gas shale; in the San Juan we have the coals, so we are agnostic as to what zone we are in, as long as it is saturated with hydrocarbons.

Investor It’s quite a change from years ago.

Lawler About two years ago, the company was looking to sell the south San Juan asset, but we asked them to wait and let us consider what we had. We are so glad they did, because we are in the core of the dry gas Mancos Shale! About five years ago, two horizontal, 5,000-foot wells were drilled in the Mancos, but not with today’s technology. We’re going to start drilling with the latest technology; we believe this will become a major play for us.

So the Greater Green River adds 2,000 locations for the company that weren’t there before. Another play is 270 horizontals and multilaterals in the San Juan, and the Mancos play has up to 1,600 locations. We feel like we’ve established three new plays for the company—on acreage we already had.

Investor What about your Eagle Ford asset; where does that rank?

Lawler In South Texas, we have great acreage with Lewis Energy Group, and we’re getting 50% rates of return there. We have thousands of wells to drill. We have 190,000 acres with Lewis Energy, and we’ve drilled over 400 wells with their team in the last five years. We have 4,800 locations iden­tified—it’s a tremendous asset. We help with completion design and other technical aspects, although Lewis Energy is the opera­tor and does a terrific job.

Investor Within BP’s North American unit, what percentage is your group versus Alaska and the Gulf of Mexico?

Lawler Initially, we were operating only two rigs at the peak of activity a few years ago, so the company was behind. We are on equal footing now. Capex continues to come our way as a result; we just received another $100 million. We are focusing on return-driven development where innovative well designs can bring on additional zones that normally wouldn’t be developed if you didn’t have your costs down.

Last year we had $1.2 billion to invest, but given low commodity prices, we have decreased our capex spend this year. We are significantly below that, but we do have a rig working in each of our business units. We are adding a few rigs this year, in most of the regions.

Investor You have more acreage in East Texas than in the other regions.

Lawler Yes, it’s massive. We have 1.4 million acres, and in some areas we hold minerals. We are just starting to drill (company-oper­ated rigs) on the minerals for the first time in 22 years—and with the latest technologies.

Investor Is this the eastern extension of the Eagle Ford?

Lawler We are focused on the Haynesville and Cotton Valley, and we do have 500 horizontal locations in the Haynesville and 100 in the Cotton Valley. But it’s such a vast area, that’s what we see today, and we are just trying to process that for now. It’s still early, and we are just trying to get our arms around it, but we think there’s a lot to do in East Texas.

Investor To adjust the portfolio, what have you bought or sold since coming on board?

Lawler We’ve bought mainly bolt-on properties, such as the purchase of Devon’s NEBU unit around the Mancos. The total we’ve spent is less than $300 million for the bolt-on acquisitions to date. We haven’t sold anything yet—our main thought was to fully understand what we have first, before we sell anything.

Investor With so many locations, would you be open to more JVs such as you have with Lewis Energy?

Lawler Sure. We’re open to JVs. We are focused on trying to develop our own prop­erties, but we’ve had a great experience with Lewis Energy. We have a premier team, so we can operate competitively at this point. This is the first time in five years that we’ve drilled wells in the San Juan … and the well results are stellar.

Investor What are some of the lessons you’ve brought to BP from your time at other companies?

Lawler At Shell, I learned the value of technical strength and economic processes used to screen projects around the world. At a small independent, I learned the process of taking a company public and how to finance a company, and from my most recent role prior to joining BP, how to manage a team of 2,000 people and simultaneously operate 44 rigs. I think that blend of experience helped me get the job.

If you can honor the brand of a company, especially one like BP, and combine that with high frequency drilling in unconventional resources, you can have a lucrative outcome.