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January 2017 Cover Story

Outlook 2017

Outlook Q&A: 2017 Trending Toward Upturn

Editor’s Note: By any measure, the downturn that began in late 2014 will be remembered as one of the most severe in the industry’s history. But if America’s independent operators have proven one thing over the years, it is that the adage about “what doesn’t kill you” is spot on. For all the pain of the past two years, U.S. oil and gas companies are seeking to come out the other side stronger, more resilient, and more capable than ever.

Industry conditions do seem substantively different at the start of 2017. In December 2015, West Texas Intermediate prices exited the year mired in the $30s and U.S. crude oil inventories were ballooning to levels not seen in 80 years. As 2016 closed, WTI had rallied into the $50s and U.S. inventories–while still historically high–were trending downward. The November election results, followed by the decision to cut production by both members and nonmembers of the Organization of Petroleum Exporting Countries, certainly helped buoy prices, not to mention the spirits of operators.

As the calendar turns to a new year, it is an appropriate time to assess the state of U.S. energy markets and look at what the near future has in store. Is the recovery real? Will the U.S. oil industry get back to work in 2017? Will natural gas activity pick up?

To answer these and other questions, AOGR presented a series of questions to J. Marshall Adkins, director of energy research at Raymond James & Associates Inc.; to Rusty Braziel, president and principal energy markets consultant, RBN Energy; to Bud Brigham, chairman and co-founder of Brigham Resources and Brigham Minerals; and to Boyd Russell, president and chief executive officer of Energy Navigator Software.

Questions are in bold, followed by the panelist’s response.

Q: Let us start with the biggest news in oil markets in some time: OPEC reaching consensus on a 1.2 million barrel-a-day production cut in coordination with an additional 558,000 bbl/d cut from key non-OPEC countries. For the record, Raymond James was predicting higher prices even before the agreement was announced. How does OPEC’s action impact the outlook for oil prices in 2017 and the prospects for a general recovery? What is a realistic trading range for WTI going forward?

ADKINS: The headline number on the production cuts is overstated, but I think we will see a legitimate 900,000-1.0 million barrel a day cut between OPEC and non-OPEC countries. That is a very big deal, and very bullish for oil markets.

There is a lot of room to run for crude prices, partly because of OPEC’s action, but also because of improving fundamentals in general. Prices are not going to surge on a straight upward line, but they are going to move higher. Most of the price gain will come in the first half of 2017. On average in 2017, I think WTI prices we be roughly $25 a barrel higher than they were in 2016.

There are always wild cards in crude oil, particularly when the Middle East is involved. But assuming no major surprises, I think we are going to see oil inventories fall through the first part of the year in the United States, which should be the catalyst to higher oil prices.

Longer term, the improving fundamentals should underpin average WTI oil prices in a range of $60-$65 a barrel for the next decade. The next few years should be higher than the longer term oil pricing because of the damage inflicted on the U.S. service industry during the past two years. The severity of the downturn has badly diminished the capacity of the U.S. service infrastructure, and we have seen meaningful attrition in a lot of areas, particularly pressure pumping. As a result, bottlenecks will have to be worked through, which will take time, before U.S. production can be increased.

Put another way, oil does not need to be at $70/bbl or higher for a long time to stimulate substantial long-term U.S. oil production growth. I think producers can find all the oil the world needs right here in the United States at a long-term price averaging closer to $60-$65/bbl. That does not mean the market won’t spend a couple years above that price range, just as we spent the past few years well below it.

That may sound like stability, but it is actually a more traditional price-driven cyclical business than we have seen in most of our lifetimes because it implies that OPEC is not in control. OPEC may tweak supply here and there to manage oil prices, but there is a very limited amount OPEC can do with its current capacity constraints. That means the industry should see much shorter up- and down cycles driven purely by supply and demand centered on that $60-$65/bbl midpoint price, at where we think it is economic to grow U.S. oil supply more than 1.0 MMbbl/d annually.

Q: OPEC’s production agreement was met with disbelief by many market observers. Price expectations aside, what does the agreement mean longer term to the global market? What are the geopolitical implications? OPEC’s track record on adhering to production quotas is suspect, to say the least. Why should the market expect member nations to behave differently this time?

ADKINS: It is a stop-gap measure, but if OPEC is able to cut half the headline number for six months, it would bridge the gap to the second half of the year, at which point our modeling shows inventories drawn down meaningfully anyway. By the end of 2017, I think OPEC will be producing every barrel of oil it can, so by definition, OPEC is relatively meaningless unless there is some kind of demand shock that requires a supply reduction to “fix” prices.

Over the next decade, I see the United States supplying all of the world’s incremental demand growth plus growing enough to compensate for production declines that are likely to happen outside the United States. Over time, these declines probably will include many OPEC-member nations also. In other words, if global oil demand grows 1.0 MMbbl/d and oil supply from outside the United States falls 500,000 bbl/d, I think U.S. producers will have no problem growing 1.5 MMbbl/d at $60-$65/bbl for a long time.

That would make the United States the world’s swing producer of oil. The difference is that the United States is not a real-time swing producer because it still has to drill the holes, fracture the wells, install the equipment, etc. All that takes time and means the production response will lag the price move by roughly a year. It is not like the old days, when all OPEC had to do was turn some valves. There will be a substantial lag factor in response to demand because the investment has to be made to drill and complete wells before supply can grow.

As far as the geopolitics, about all one can do is speculate. I believe Saudi Arabia and other countries pushed production to unsustainable levels as part of what I call a “fake surge” ahead of the OPEC annual meeting so they could use those artificially high numbers as the base from which to negotiate production cuts. I think much of OPEC’s “stated” production capacity simply does not exist. An example is the Saudis’ claim they can produce close to 12 MMbbl/d in short order. If it has all of this excess capacity, why has the Saudi oil rig count more than doubled over the last five years while its oil inventories have collapsed around 15 percent over the past year? That logic doesn’t make sense.

My unprovable theory is that Saudi Arabia was producing at or near capacity this summer, and was not comfortable trying to sustain 10.8 MMbbl/d indefinitely. The Saudis were going to cut oil output anyway! Saudi Arabia already had won the price battle. By the time OPEC met, low oil prices had seriously degraded U.S. service infrastructure, and its archenemy, Iran, had recovered its oil production to presanction levels. There was no longer a reason to keep oil prices artificially low.

Also, one has to consider the implications of low oil prices on Saudi Aramco’s initial public offering. The bottom line is there were a lot of reasons for why it was in Saudi Arabia’s interest to cut production and raise oil prices. It probably was going to cut anyway, so why not get others onboard to broker an agreement?

As far as non-OPEC countries, I don’t think their announced cuts are very meaningful. Russia, for example, is cutting from an absurdly high, unsustainable number. It essentially is reducing output to what is sustainable. Mexico’s cuts are simply natural declines that are going to happen anyway. So that leaves OPEC cutting about 800,000 bbl/d from what is a more sustainable production level.

We think compliance will be high with two-thirds of the cuts coming from Saudi Arabia, the United Arab Emirates, and Kuwait. Those countries usually always abide by cuts. We probably won’t have a good indication of compliance until the six-month period is halfway over anyway, but I suspect those three will do exactly what they have agreed to do.

The intriguing one is Iraq. I would not have thought Iraq would have agreed to a significant cut. The magnitude of its cut tells me Iraq probably didn’t have the capacity to maintain production at its previous level, either, so that probably ends up being another cut that was going to happen regardless.

Q: International Energy Agency data showed that global supply and demand had moved into balance by the second half of 2016. The “oversupply” problem has come down to an inventory problem, with commercial stocks around the world estimated at nearly 3 billion barrels in December. What trends are you seeing in inventory withdrawals/additions? What is your overall outlook for U.S. oil inventories in the months ahead and the timeline for depleting the overhang?

ADKINS: We think U.S. inventories are going to continue declining meaningfully. In fact, we see quarterly oil inventory drawdowns within Organization for Economic Cooperation and Development countries every quarter next year. Inventories should look bullish, but it hard to predict the timing of exactly when OECD inventories will return to normalized levels (i.e., sufficient to meet 30 days of demand). My guess is that OECD inventories will get back to normalized or even below-normalized levels just after mid-2017.

The tough part about global inventories is that only half the world’s inventories are measured and publicly reported. These are OECD oil inventories. Even then, with the exception of real-time U.S. inventory data, finalized OECD oil inventory reports tend to lag reality by two or three months. In addition, there are seasonal and price-induced periods where global oil inventories “slosh around” into or out of the United States and OECD countries. This sloshing-around effect can make the numbers misleading.

We believe global demand has been stronger than most people realize. That is why we saw meaningful drawdowns outside the United States in 2016, which showed up in IEA numbers in the third quarter. If inventories are falling, the market is undersupplied. It’s that simple! That is what our model suggested and that is what I believe the IEA oil inventory data confirm.

I think we will look back and see inventory drawdowns in late 2016 and the first half of 2017 as the key catalyst that moved oil prices higher. With higher prices, OPEC will ramp up production as best it can to a sustainably high level by the third quarter, but the market still will be undersupplied because the response time in the United States will be slowed by diminished service and supply capacities. The end of the inventory overhang means the market will be subject more to the forces of real-time supply and demand, but it also means the inability for supply to respond to increased demand on a real-time basis.

Q: The full impact of the downturn on U.S. oil production is not yet fully known, but from April 2015 to the end of third quarter 2016, EIA data indicated that domestic output fell roughly equivalent to OPEC’s 1.2 MMbbl/d announced cut. As unpleasant as the past two years have been, what has the industry learned about the economics and sustainability of tight oil plays? Are the dramatic break-even cost reductions seen in these plays permanent? What insights have been gained on decline curves and productivities? What pricing point will ensure U.S. oil production growth without creating another oversupply situation?

ADKINS: The market is coming to grips with the fact that there is a lot more capacity to grow U.S. oil supply than anyone thought possible, and the price at which it can be extracted economically keeps moving lower. The United States has transitioned from being the highest-cost producer a decade ago to arguably the lowest-cost producer in the world today (if social costs are included).

There is no question that oil service pricing is going to bounce back in a significant way in 2017; oil field pricing has been at unsustainably low levels for nearly two years now. At the same time, however, operational efficiency will continue to improve. The dramatic break-even cost reductions seen in 2015 and 2016 as prices collapsed were partially the result of lower service costs and partially the result of better operational efficiencies.

Cyclically, we are going to see a surge in service costs in 2017-18 that may temporarily offset continued structural cost improvements resulting from better operations and technology applications. In fact, we expect a fairly large increase in 2017 completion-related costs as the industry struggles with bottlenecks in pressure pumping services and equipment.

However, it is important to understand that the higher service costs are not going to destroy shale play economics in any form or fashion. We simply have gotten too good at drilling and completing horizontal wells. U.S. production economics should be rock solid at $60-$65 oil, and break-even costs will continue to edge downward over the longer term.

Getting decline curve projections right is all about doing the math right. Shale plays do decline very steeply within the first few years, but the shape of most of the curves is very flat once one gets past the first few years. After the initial production hit following the price crash in late 2014, the average U.S. decline rate actually has shrunk with fewer new wells being completed. We are now more than two years into the downturn, and the average U.S. oil well decline rate today is lower than it was three years ago.

That means we can grow production today at a lower rig count not only because new well productivities are better, but also because so many shale wells are farther out on the decline curve, where production rates are lower but stable. If activity does what we expect over the next few years, those decline rates will start to move back up as new wells are added to the mix.

I see a very bullish two-three years ahead for the U.S. energy business. The recovery has begun, and at the right price, the United States can achieve a net growth of 1.5 MMbbl/d over the next decade to satisfy world demand.

With the new, more price-driven cyclical oil market, the see-saw of supply and demand makes another “overbuild” inevitable. Hopefully, the next one will result in nowhere near the oversupply we saw in 2014. In the meantime, U.S. producers should see much better times. They certainly have earned it after the past two years.

Q: EIA estimated 20 years ago that the nation had 167 trillion cubic feet of proved natural gas reserves and 1.156 quadrillion cubic feet in technically recoverable resources. Two decades’ worth of consumption later, EIA puts those numbers at 324 Tcf of proved reserves and nearly 2.300 quadrillion of technically recoverable resources, thanks largely to shales. The rise of U.S. shale gas has been nothing short of remarkable, but what does the future hold for gas shale plays?

BRAZIEL: The future of the shale revolution is about demand, both in the United States and exports in the form of liquefied natural gas to overseas markets and pipeline deliveries to Mexico. U.S. producers have proven they can meet almost any rational level of gas demand, if the price is right. So much of shale’s future will turn on whether demand will support a price high enough to drive continued increases in drilling activity.

Three factors will be the primary determinants of this demand. The first is the U.S. regulatory environment, running the gamut from production rules to pipeline transportation and constraints on natural gas end-use markets. The other two factors–the health of the global economy, and the price of crude oil–will influence demand for U.S. LNG export volumes in overseas markets, and therefore, the likelihood of a second wave of LNG export facilities. If the demand is there, the recoverable resources are available for U.S. producers to meet that demand.

Q: For the first time since 2005, year-to-year U.S. natural gas production was down in 2016, averaging about 1.5 billion cubic feet a day less than in 2015. The Marcellus/Utica has been the primary contributor to increased domestic production, but Appalachian output stalled in 2016 with low commodity prices. Will Marcellus/Utica production resume growing in 2017? Will increased productivities per well and per rig continue? What about the other major shale gas plays? What do you envision in these basins over the next 12-18 months?

BRAZIEL: It is quite likely that Marcellus/Utica production will resume its upward trajectory, primarily because of pipeline capacity out of the region being added over the next couple years. Local prices for Appalachian gas have been considerably below prices in most of the rest of North America for the past few years, mostly because of pipeline capacity constraints. As these constraints are relieved, producers will enjoy higher net backs and more attractive drilling economics, encouraging them to drill more wells. The obvious result will be production growth.

In regard to increasing rig and well productivities, we certainly have seen continuous improvement since the start of the shale revolution. Of course, trees don’t grow to the sky, and at some point, that productivity improvement will slow. But across core parts of the most rapidly developing basins, there is little evidence of that slowdown happening yet. And as new shale development regions open, the industry will again learn how to “break the code” in those regions, which will initiate new rounds of improving productivity.

We are starting to see some interesting developments in the Haynesville/Cotton Valley region in Northwest Louisiana and East Texas. But it turns out that some of the most exciting gas developments actually are in the crude-dominant basins, particularly the Permian and STACK/SCOOP plays in Oklahoma. These plays are throwing off a lot of associated gas, which for most producers has a negative break-even price. That is, the producer can make enough on crude oil and condensate production to achieve an attractive rate of return, even if the gas is sold at a price less than zero.

Those economics have the potential to wreak havoc with regional gas markets in Oklahoma and the Permian. Add to that big new potential plays such as Apache’s Alpine High development, and those markets may become further unsettled.

As to the final part of the question, with all the new pipes being built out of the Marcellus/Utica and favorable production economics in the basins, Appalachia will be responsible for most net gas production growth over the next five years. But assuming oil prices continue their gradual recovery, expect to see increasing production out of the Permian, STACK/SCOOP, Bakken and Niobrara regions. And watch out for the Haynesville/Cotton Valley. That area was given up for dead, but definitely is coming back to life.

Q: In 2015 and 2016, the Federal Energy Regulatory Commission approved more than 70 pipeline projects totaling 28 Bcf/d in capacity and consisting of 1,540 miles of pipeline and 1.7 million compression horsepower. Do you expect a continued high level of investment in pipeline projects in 2017? Where is the next round of projects planned? How are take-away capacity additions impacting the market and changing gas flows across the country?

BRAZIEL: We definitely anticipate a high level of pipeline investment over the next two or three years, with most new capacity being built to move gas out of the Appalachian region, or to deliver that gas to downstream markets.

Our analysis identifies about 18 Bcf/d of Appalachian take-away capacity that will ease the constraints out of the region. We organize those capacity additions into five corridors: six projects totaling 3.3 Bcf/d to the New England and Mid-Atlantic states, two projects with a combined 650 million cubic feet a day to Canada, four projects totaling 4.3 Bcf/d to the Midwest through Ohio, seven projects totaling 4.5 Bcf/d to the Gulf Coast through Ohio, and four projects totaling 5.2 Bcf/d heading to the Southeast along the Atlantic Coast. There are other projects planned for the region, but they mostly move gas within Appalachia rather than adding to take-away capacity out of the region.

While all of the take-away projects are “on the books,” not every single project may materialize as planned. Some may face cancellation, such as Kinder Morgan’s Northeast Energy Direct project, while others will deal with long delays, such as those experienced by the Williams Constitution Pipeline. But even if a few more of these projects are delayed for long periods or cancelled, there still is more capacity being developed than likely will be filled in the next five-seven years, which suggests the possibility of an overbuild, at least in the medium term.

Reversing the direction of Northeast natural gas flows is the most significant transformation in the natural gas market I have witnessed in my 40-year career. Instead of gas moving north and east toward the region, gas increasingly is moving south and west out of the region. As new pipeline capacity continues to open, even more supply will move directly to the Gulf Coast to meet rapidly increasing LNG and Mexico export demand, or will displace Gulf Coast supplies that traditionally have served other regions, such as the Midwest. Either way, we are headed toward a market where the Northeast is a net supply region and the Gulf Coast is a net demand region–a radical development that has the potential to upend everything we thought we knew about regional price differentials and forward basis relationships.

Q: Looking at the demand side of the ledger, do you expect any potential surprises in 2017? U.S. natural gas consumption grew 5 Tcf annually between 2005 and 2015. Do you envision demand growing at a similar pace over the next decade? Which sectors are most important to sustained demand growth, and what are the key challenges in attaining that growth? How big a role will LNG and pipeline exports play over the next few years in expanding the market for U.S. natural gas?

BRAZIEL: The U.S. natural gas market always has the potential to surprise, and most of the time the culprit is weather. Late, severe winter weather will always strike fear in the heart of the gas market, and that is still true even at today’s high production levels. But other than that, we do not expect any big surprises in 2017. Slow growth in production is likely to continue during 2017, along with a relatively balanced market.

Future demand growth will be lumpy, depending on weather and the dynamics for LNG exports. The sectors most important to demand growth clearly are exports and gas-fired power generation. Both are poised to experience significant growth, which will be good for natural gas demand and pricing.

LNG and pipeline exports to Mexico will play a huge role over the next few years, by far the most significant aspect of the U.S. natural gas market. Because these volumes are expected to flow on a relatively consistent basis–meaning not so dependent on weather–these new sources of demand promise to add important pricing dynamics to the natural gas market.

For example, today, if natural gas prices increase during the summer, then gas is displaced by coal for power generation, which acts to mitigate further price increases. But this kind of market response may not happen in export markets. The big question is whether high gas prices will curtail LNG exports, or will those exports (since the volumes are fully committed to overseas buyers) flow anyway, regardless of price? With 10 Bcf/d-12 Bcf/d of export volumes soon to be part of these markets, that is a wild card we all will be waiting to see played.

Editor’s Note: On Dec. 14, Diamondback Energy Inc. and Brigham Resources announced an agreement for Diamondback to purchase Brigham Resources for $2.43 billion, giving Diamondback more than 76,000 net acres of leasehold interests and 182,000 net surface acres in the Permian Basin. The deal included only about 5,000 net acres of the more than 36,000 net acres of minerals owned by Brigham Minerals.

Q: You started Brigham Exploration in 1990 with an initial investment of $25,000, and sold it 21 years later to Statoil for $4.5 billion. You then re-entered the business as chairman of Brigham Resources and Brigham Minerals. How would you assess the level of opportunity available to smaller independents? What general types of business strategies appear most favorable over the longer term for independents? What do you see as the biggest business challenges to establishing and growing a successful small independent?

BRIGHAM: Our businesses–from Brigham Exploration to now Brigham Resources and Brigham Minerals–have focused on leveraging the latest technologies and superior knowledge bases to identify and optimally exploit the highest-margin and economically advantaged oil and gas resources. In the 1990s, the most significant technological leverage was provided by 3-D seismic, which previously had been viewed as a purely exploration tool. Our growth was driven by our pioneering success with that technology.

Today, more than ever, the opportunities presented to independents are technology related. Horizontal drilling and completion technology have combined to create a tight reservoir revolution in the United States, a renaissance that is affecting the entire globe. In our view, we are in the early stages of this renaissance, and it will continue for many years or even decades. This presents both challenges and opportunities for entrepreneurial independents.

Associated with this dynamic and rapidly evolving environment, there is more differentiation by operator today than ever in the industry’s history. This is particularly apparent for plays in the early stages of delineation, where often there are widely different economic outcomes even in adjacent drilling units. The outperformers are the experienced companies that are providing a creative environment, and that encourage innovation and measured, intelligent risk taking. Such operators are outperforming their peers substantially, including most of the large independents and majors. That stated, adopting best practices over time, facilitated by service providers, will deliver some convergence of outcomes.

This is a dramatically different world for independents, and it presents very different challenges. As noted, operational expertise and innovation are separating winners from losers. But there is another differentiator. In this low-price environment since late 2014, the economic competitiveness of basins and plays is more dispersed than I have seen in my career. We are blessed to be operating in the Permian Basin, and it is apparent that it is among the best oil and gas real estate in the world. In time, it may prove the very best. As we emerge from the trough in oil prices, the Permian will be providing the marginal barrel where supply meets demand.

No other basin compares with the Permian, both in terms of current economics and the ultimate resource. Of course that is a significant challenge for independents not already in the basin, as the cost of entry is an order-of-magnitude higher than it was in the past, presenting capital-scale challenges.

Furthermore, the capital-scale challenge only starts there, given that the cost of drilling and completing wells also is an order-of-magnitude higher. Given that it is crowded and expensive, independents could consider seeking out and staking smaller positions in the Permian, which hopefully could be grown over time, or explore for the next high-quality tight reservoir play.

Q: Finding and developing reserves in U.S. onshore basins is a very different proposition than it was when you began your career. From a geophysicist’s perspective, how would you summarize the evolution of the geosciences in resource plays? What lessons have you learned in applying seismic technologies to optimize the performance of unconventional reservoirs, and what tools or methods do you see as critical to the economic development of those assets?

BRIGHAM: In some ways, geophysics has moved from “finding the reservoir” to “defining the reservoir.” Using microseismic techniques to monitor the reservoir has become an important tool in understanding future reservoir development and well spacing. Microseismic will become increasingly important as these large multilayered fields are developed.

Also from the geosciences perspective, many things have changed as oil and gas exploration has moved from producing a reservoir to producing a source rock. Understanding the parameters of the resource rock is tantamount to success in exploration.

However, some of the tried-and-true methods have not changed, such as looking at all the data, developing models, testing the models, obtaining new data, continuing to refine the model, etc. All of that will never change.

The types of data collected and evaluated have changed, however, and now include geochemical parameters. The specific application of geophysical interpretation techniques continues to be necessary in steering horizontal wellbores–particularly in structurally complex terrain–in order to mitigate geologic hazards. In addition, companies are using extensive 3-D datasets to identify and map various attributes of source rocks to maximize estimated ultimate recoveries. Much hard work and interdisciplinary collaboration is necessary to discover and exploit resource plays.

Q: Geophysics aside, what operational skill sets and technological proficiencies will be most important to success for independent companies going forward? What types of drilling, completion and production best practices will enable the next productivity gains and cost reductions? Do you see any new technologies or applications that could move the needle on development economics and reserves recovery?

BRIGHAM: In many ways, the tight reservoir revolution has turned the fundamental business upside down relative to 20 years ago. To put it in simple perspective, instead of drilling for high-porosity and high-permeability reservoirs on structural highs, we are targeting tight reservoirs and source rocks in basin-centered lows. Instead of mobilizing a rig to move 20 miles to drill a 10-20 percent probability exploration well, and subsequently move it again 20 or so miles to a new location, we essentially are moving rigs a matter of feet to drill very high-probability development wells. In these giant unconventional oil fields, the technologies and equipment needs are drastically different than in the world of conventional reservoirs, and they are evolving very rapidly.

Our experience has demonstrated that increases in proppant and fluids pumped in stimulation treatments are powerful levers for increasing production. Not long ago, 3,000 pounds of proppant per lateral foot was unheard of, and now operators are pushing toward densities of 5,000 pounds per lateral foot. At some point, especially in a lower-price environment, there will be diminishing returns, but we are not there yet.

We are also big proponents of pad drilling. However, like others in West Texas, our early priority is to drill our leasehold to hold it by production. In time, pad drilling, such as we conducted in the Bakken Shale play, will enable us to further drive down drilling and completion costs to further enhance margins.

Last, multilateral drilling and refracturing will have very important and positive roles to play. Again, we are in the early innings. The best is yet to come!

Q: Market conditions since late 2014 obviously have been trying for the entire industry, but you have managed businesses successfully through both up and down cycles. What advice would you offer executives responsible for navigating smaller companies through the current downturn? What can independents do to ensure they will be prepared for an eventual recovery, particularly in regard to personnel, property, and capital preservation?

BRIGHAM: I think it is apparent that we are in the early stages of a recovery. But the world has changed. Thanks to the U.S. shale renaissance, we largely have disrupted the cartels, and over time, the United States increasingly will be the more efficient and agile “swing producer.” Outside of extreme disruptions, I expect the amplitude of price cycles to be less pronounced, to some degree similar to our experience with natural gas subsequent to the tight gas renaissance earlier this century.

We are making oil markets more liquid and efficient, to the benefit of the United States in so many ways. Despite less volatility, our business still carries substantial risks, thus limiting debt leverage to conservative levels is always wise.

In terms of driving success, there is nothing more important than people and giving them the freedom to be successful in an environment that encourages innovation and intelligent, measured risk taking. Our people, and our environment, drove the success of Brigham Exploration, and the outstanding employees of Brigham Resources and Brigham Minerals are driving our success today.

Q: Merger and acquisition activity is forecast to increase this year as companies begin formulating strategies to capitalize on growth opportunities in a recovering market. The first step in making an acquisition, of course, is identifying an asset. What can operators do to enhance their ability to screen multiple properties and datasets to find the right fits? What tools and methods can be employed to help identify the best available acreage, based on an operator’s specific criteria?

RUSSELL: First and foremost, operators do not want to get carried away by the optimism that comes with a recovering market. Remember, in order to complete an acquisition, the buyer is going to have to pay more than the seller’s retention value. That magic number will not be revealed, but the buyer can be assured it will be close to market value, except in desperate cases. For the potential acquisition to be a win, the acquirer must find additional value that the owner does not see or is unable to realize.

It seems obvious, but buyers should start the process of identifying assets by narrowing their focus. It is not practical to try to consider every unconventional play in the lower-48.

The first priority is getting the C-suite onboard with the plan. Pushing the price above corporate metrics often involves strategic benefits beyond the knowledge of the evaluators. Another key issue is deciding where to be and why. This means understanding whether one is trying to expand his influence or build a new core area.

The next step is determining financial capability. The value of any deal is in the producing property plus the upside. To realize that value, you will need to spend both the acquisition price plus the cost to develop the upside. Are you prepared for that?

Once the where, why and how questions are answered, the next issue is figuring out “what” to acquire, including determining whether the goal is to acquire a company or an asset. As potential acquiring companies refine their focus, they should take inventory of their strengths relative to other operators in the focus area.

Once these broad points have been considered, screening can start in earnest. It will involve mapping parameters to find which companies hold land in the focus area, and what the performance metrics are on a regional basis. This process includes reviewing U.S. Security & Exchange Commission filings, company press releases, analyses from investment houses, and bankruptcy filings.

One point to consider is that the buyer should not pay for undrilled locations that the seller is not able to finance. If you have cash flow and debt capacity, the rewards from that capacity accrue to you. So if one of your strengths is a strong balance sheet, look for companies that do not have that strength.

In keeping, if the buyer is a top-decile operator, or has hired a top-decile completions engineer, it should look for operators who are not as far along the learning curve. If a company is driven by acceleration and early cash flow, it should look for assets that are completed with fewer stages per meter of pay, or companies that use extended choke management. Different metrics create the opportunity for different evaluations, and therefore, win/win potential for a transaction.

Large companies usually spend more to drill because their standards are more stringent, but they also are less likely to dispose. Accordingly, small independents should look for noncore big company land. Their opportunity is both lower development cost and timelier drilling.

What do you know about geology that others do not? Does this create opportunity?

These are only a few suggestions for narrowing the search and creating a deal that can be mutually beneficial to buyer and seller. Hopefully, these will trigger other ideas for many other tactics one can employ to quickly and effectively choose strategic opportunities.

Once you have narrowed your search and understand what criteria are important to your company decisions, using consistent software processes to evaluate the viable opportunities will help increase your confidence. Establishing a process that is consistent will prevent the need to “reinvent the wheel” each time you evaluate, and will help identify where opportunities may overlap so as to be ranked or prioritized.

Q: The final months of 2016 saw acquisition deals from the likes of Anadarko, EOG Resources, Oxy, Concho Resources, Callon, and RSP Permian, as well as small players such as Krewe Energy, Silver Run, and Charger Shale Oil. What are the challenges specific to smaller companies in evaluating reserves? If timing is everything in acquisition deal making, how can smaller companies with limited personnel and less capital to risk level the playing field with respect to both speed and accuracy?

RUSSELL: First, with limited personnel and capital, small companies must be selective in investing in evaluation efforts; time spent on failed bids means other profitable work is delayed, or worse, left undone. They also should follow the guidance on screening. This includes examining the competition for acquiring a property and avoiding “fighting a big dog in his own backyard,” or in other words, outbidding a large company with neighboring operations that can easily (and cheaply) operate the target property with small incremental cost. The key is for small firms to target properties where they are as much the “natural owner” as any competitor, or better yet, where they are clearly the natural owner.

Second, they should not worry about reserves until they have found the right candidate(s), but they should take the time for full economics on each well. Forecasting and evaluating wells as a group can lead to misleading results. Undeveloped resources typically are assessed using type wells that usually are reliable when constructed using both history and forecast. Do not trust type wells that use history only.

Third, remember that not all evaluation software (forecasting, economics and reserves) is created equal. Traditional software used by large U.S. companies was created 40 or more years ago and was designed to evaluate one well at a time. Modern software is designed to evaluate thousands of wells at a time. This design difference creates productivity improvements that can be as much as 10-fold. Small companies are agile enough to realize this benefit.

It also is important to look for assisted forecasting that works. Most software has assisted forecasting, but the results are not particularly good, compared with what an engineer would accept if he was to forecast manually. A good assisted-forecast algorithm should meet internal standards 90-95 percent of the time, requiring the analyst to tweak only a few wells.

Finally, when negotiating a transaction, remember that arguments usually come down to price. From my experience, those with high success in closing deals look for things other than price to create a win/win. It is important to take the time to know the seller so a deal can be structured that looks at the seller’s other needs.

Q: From the buyer’s perspective, what best practices and procedures are most important to ensuring accurate evaluations of reserves in place and identifying upside potential? What can potential buyers do today to ensure they have the right workflows in place to facilitate property evaluations as deals become available? On the other side of the ledger, how can a seller be certain an offer represents fair market value?

RUSSELL: The principle of “buyer beware” is important to remember in any purchase decision. Buyers must be properly cautious with proprietary third-party reports or reserve house audits. Is it explained why that evaluator was chosen? What experience does it have with the properties or the area? The acquiring company should review the reports/audits and use them to inform itself, while keeping in mind that although intended as independent results, a reserve evaluation is always subjective. That third-party evaluation likely was done from the perspective of the seller’s business, its strengths and its goals, so any report prepared for a disposition may reflect the seller’s viewpoint.

Even without this possible situation, offers against a reserve report always will go to the buyer with the highest price deck and the most money to spend. Instead, companies should look for real opportunities that will permit them to bid higher because they have found more value.

Any workflow should consider both the “micro” and “macro” levels, or in other words, in detail as well as at a higher level. Let us examine the micro considerations first. Individual technical staff will focus on their parts of the evaluation with this guidance. If the seller has proprietary data, those data would be used in preference to public data. Of importance is the producing hours for each well, better allocation of production to wells, daily data, and completion details.

I always start with an assisted forecast of all wells, followed by a review and subsequent adjustment of the forecasts I do not like. Regional operating costs then are assigned to create a first-cut economic value that is about 90 percent accurate. Generally, this takes about two hours per 1,000 wells. With more than 1,000 wells, I omit the initial forecast adjustment, which results in an 80 percent solution.

If the acquisition is friendly, I would compare my results with the company’s reserve report to identify any discrepancies. This sometimes triggers a go/no-go decision if agreement cannot be reached on the producing value.

Undeveloped assets are valued using type well profiles combined with a rudimentary drilling schedule. If there is a difference in type well profiles, it usually is the result of incorrect type well construction methods or using nonrepresentative wells to build the type well.

When it is determined that the evaluation is close enough that a deal is possible, then production forecasts are refined, lease operating statements are reviewed to get proper ratios of secondary products, costs, shrinkage and price offsets. Land records are examined to refine burdens. Finally, the development will be examined closely to identify upside that may be unknown to the seller.

At the macro level, I try to consider broader trends in the data and ensure consistency in the individual staff work. Individual evaluation areas may not have sufficient data to find such trends, but across the entire acquisition, the trends may be evident. Examples could be poor performance of wells completed during a period when a new completion was being tried (including frac jobs that connect with neighboring wells). Typically, a seller will undertake the same evaluation process, but that would have been done as part of the reserves process.

Q: Decline and material balance forecasting software with analytical tools for economic modeling and risk management have become the new standard in reserves evaluations. But any evaluation is only as good as the data input into the process. What are the various types of data that can be incorporated into an analysis? How much preparation is required to integrate those data? How can operators gauge the quality of available data so they can have confidence in the results while assuring compliance with applicable regulations and standards?

RUSSELL: In all cases, I recommend examining both the seller’s proprietary data (from the data room) and public data to ensure consistency. Any discrepancies should be questioned. It is important to understand the limitations of whatever datasets are being used. For example, if it is public data, the evaluator should know whether the data are reported by well or reported by lease and then arbitrarily allocated to wells.

The buying company also needs to determine how much confidence can be placed in forecasts from only monthly production data by comparing those forecasts in some wells to forecasts from full datasets, including daily allocated and well test production data as well as pressure data.

Also, it is always useful to “sense-check” the data to find anomalies, either real in the reservoir or artificial in the data. A quick screen using a “data view” mapping of key data parameters is helpful.

Understaffing is a reality in today’s market, and that can make it difficult to do a good job of screening data quality. To compensate for this, I would use the Pareto principal to look at the wells with 80 percent of the producing value. As part of the due diligence, I would scan well files and completion reports for disturbing trends.

I also would have discussions with engineering staff to gauge their level of experience and competence relative to my own company. And finally, I would do a sensitivity analysis to define how much value impact comes from uncertainty in data quality.

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