Every August since 1996, investors and attendees at EnerCom's The Oil & Gas Conference® in Denver ask the same question: “Which micro- or small-cap company presentations should I focus on?” This year’s edition features approximately 120 presentations from public and private companies operating on six continents. To aid investors, here is a short list of companies with unique strategies and opportunities in a few select operating areas.

Eastern Colorado

Nighthawk Production LLC made a positive first impression on investors and analysts at the 2013 conference with news of its eastern Colorado Mississippian-age discovery, the Steamboat-Hansen 8-10 well. Costing $1.4 million, this vertical well was drilled more than 8,000 feet through the Pennsylvanian-age Cherokee Formation to the base of the Mississippian-age Spergen Formation, producing some 50,000 barrels of oil (bbl) in the first six months.

“The well paid back in less than three months, indicating the potential commerciality of our Arikaree Creek Oil Field in Lincoln County,” said Michael Thomsen, Nighthawk’s president. “After our second well, the Taos 1-10, a 40-acre offset to the Steamboat well, came on at 500 barrels of oil per day with no water and produced at that level for over a year, we knew we had something unique.”

The company is still evaluating the dolomite reservoir at Arikaree Creek, where Nighthawk believes there is a hydrothermal component enhancing porosity in the area. Thus, since last year’s conference, Nighthawk has been busy evaluating the areal extent of the attractive geologic characteristics beyond Arikaree Creek.

Nighthawk’s team, based in Highlands Ranch, Colorado (a suburb 15 miles south of Denver), created a geologic model based on the nine wells drilled at Arikaree Creek and identified a couple of dozen additional prospects and leads, the first of which was successful.

“We drilled the first of our prospects and announced a new Spergen discovery in April 2014--the Snow King well,” said Thomsen. “The strong similarities between Arikaree Creek and the new Snow King well gives us confidence that there are more discoveries to be made that will ultimately drive production levels and cash flows.”

The plan forward is clear: Continue development drilling at Arikaree Creek and Snow King, drill multiple other exploration targets derived from the geologic model, and drill additional wells in the Limon area where the company has production from stacked-pay Pennsylvanian-age formations.

Nighthawk expects to run one rig in the play for the remainder of 2014 with the potential to add a second rig to ramp up drilling and production.

“Two years ago, our production profile was only a few tens of barrels and we thought our potential was in the Pennsylvanian-age horizons,” Thomsen said. “Now, we’ve made multiple Mississippian-age discoveries and we’re producing 2,100 barrels of oil per day.”

With Nighthawk's current plan in place, Thomsen believes the company could potentially reach 4,000 bbl/d by the end of 2014.

“There are always mechanical and technical challenges when drilling new plays, but we have encountered, overcome and learned from many of these in the recent past,” Thomsen said. “We have a very solid development plan in place which we believe mitigates risks to us and we’re excited to see where it leads, but more importantly, we believe we have the best exploration, drilling and operations team in eastern Colorado led by Chuck Wilson, Nighthawk’s COO.”

Eagle Ford Shale

One year after the Eagle Ford Shale play surpassed 1 MMbbl/d, more than $13 billion worth of Eagle Ford assets have changed hands. The play has been a breeding ground for global oil and gas companies eager to enter the market, rapidly grow production and be sold, or purchase other producing assets.

Perhaps the newest Eagle Ford name at this year’s conference to hit U.S. exchanges is Lonestar Resources LLC, an exploration and production (E&P) company with a 23,079-net acre position in three active development areas in the oil window of the Eagle Ford.

“We believe the continued entrance of large participants into the Eagle Ford is a significant endorsement of the Eagle Ford’s relative returns,” said Frank D. Bracken III, CEO at Lonestar, based in Fort Worth. “Operators all over the world want access and exposure to this play.”

Lonestar has been opportunistic in putting its Eagle Ford position together over the past two years through purchasing working interests in individual leases and wells, acquiring properties out of bankruptcy, taking primary term leases and identifying farm-in opportunities. In March 2014, Lonestar closed on its biggest transaction to date by purchasing 13,156 net acres in the Eagle Ford Shale trend from Clayton Williams Energy Inc.

“In January 2013, we outlined a plan to reach an initial net leasehold objective of 20,000 net acres in the proven areas of the Eagle Ford Shale trend within 24 to 36 months,” Bracken said. “With the help of this transaction and our operational team, it took less than 14 months to achieve our objective.”

The company’s strategy is straightforward: aggregate small interests in three core areas and over time build these positions out to a significant mass and scale with production and reserve additions.

“We believe 40,000 to 50,000 net acres is a number that yields real materiality to the market,” Bracken said. “This is the level where you can build a significant drilling inventory that will support our growth goals.”

Lonestar's interests dive deeper than just acquiring land, though. The company is aggressively turning the bit to the right to grow production, cash flow and reserves. It produced an average of 3,800 boe/d during first-quarter 2014 and had more than $564 million of proved reserves value discounted at 10% at year-end 2013.

“We have the liquidity to fund our two-rig, 21 well-per year program almost completely out of internally generated cash flow while leaving our $109 million undrawn revolver available to expand our footprint in the Eagle Ford,” said Bracken. “Time is the enemy of IRR, and being a returns-driven company, we will aggressively and responsibly develop our asset base to generate the greatest returns possible.”

Lonestar has additional upside from 35,000 net acres in Roosevelt County, Mont., that are prospective for the Bakken and Three Forks Formations. But the majority of the company’s capital and resources will be concentrated on the Eagle Ford for the time being.

“Our focus remains in the Eagle Ford, as 95% of capital will be deployed there for the foreseeable future,” Bracken explained. “That said, we will do the necessary work to attract a strategic joint venture partner to move our Bakken position along to realize a return for the company and our shareholders.”

Bakken/Three Forks

Samson Oil & Gas Ltd. is a small-cap Denver E&P with a unique set of oil assets. The company’s near-term focus is development drilling in the Bakken/Three Forks plays in the Williston Basin, where it has employed farm-ins and acreage swaps to develop its horizontal well inventory, build its oil production levels and mitigate risk over the longer term.

“Operational control for Samson is good, but it’s not mandatory,” said Terry Barr, CEO at Samson. “Growth is more important to our company at this point.”

A small company with exposure to five operating areas may sound complicated, but Samson’s near-term focus is clear.

“The plan for the second half of 2014 is simple—complete our 16-well Bakken/Three Forks infill well program at North Stockyard with our operating partner Slawson Exploration,” said Barr. “These wells will provide immediate production and cash-flow growth, allowing us to firm up the balance sheet and reallocate capital to our future development plans.”

Slawson Exploration is a private, Denver-based Bakken operator with ample resources and access to services, which should facilitate more rapid development of the project.

The North Stockyard project covers three sections in Williams County, N.D., the core of the Bakken Shale. Samson holds a 25% working interest or about 503 net acres. In 2013, Samson farmed out its working interest and operatorship to Slawson.

Currently, six of Samson’s eight Middle Bakken wells are complete and producing; two have been fracked and are waiting to be turned into sales.

“Our wells are being drilled on pads, meaning that we expect the production increases to be lumpy, as more than one well will be turned over to production at once,” Barr said.

Current production net to Samson from North Stockyard is 595 boe/d (May average) and accounts for 80% of Samson’s total producing assets.

Samson and Slawson are doing more than just Middle Bakken development at North Stockyard. Progress has already begun on developing the Three Forks resource.

“We’re almost done with our first two Three Forks wells--the first was completed on May 29,” said Barr. “The Three Forks laterals are longer than the Bakken ones. They’re a section and a half, or 9,000 feet, while the Bakkens were one section, or 6,000 feet.”

Barr explained the reasoning for the various lateral lengths, given current industry practice to use 1,280-acre drilling spacing units.

“North Stockyard was first drilled in the early days of the Bakken before 1,280-acre spacing became the standard,” he said. “Our first Bakken well was on 640- acre spacing, and once you drill one of those you have to stick with that orientation.”

The 16-well program will carry Samson through the end of calendar year 2014. Barr believes the Rainbow project in Williams County, N.D., also focused on the Bakken/Three Forks, holds potential to create the next step-change in growth for the com- pany.

“Continental is the operator of our 950 net acres at Rainbow,” Barr said. “We’ve identified 16 opportunities, eight of which are in the Bakken and eight are in the Three Forks. The first well was to spud in June.”

As with any small company, financing is a hurdle. Barr believes Samson’s strong relationship with its lender, Mutual of Omaha Bank, and future cash-flow generation from North Stockyard, will provide the necessary liquidity for the company to reach its near-term operational objectives.

Marcellus Shale

Pioneer operators such as Range Resources, Cabot Oil & Gas, EQT Corp. and XTO Energy have pushed average finding and development costs in the Marcellus Shale well below $1/Mcfe, making it one of the most profitable basins in the continental U.S.

While these major growth companies are household names to industry followers, some may have missed a small company poking holes in the right neighborhood.

Since 2008, Trans Energy Inc., a publicly traded E&P based in West Virginia, and its joint venture partner, Republic Energy Ventures, have quietly built an enviable position in the heart of the Marcellus Shale.

The partnership has about 42,000 net acres spread across Marshall, Wetzel and Marion counties, W. Va., with neighbors such as Antero Resources, Magnum Hunter Resources, EQT Corp., Chesapeake Energy and Gastar Exploration.

“We already have over 300 locations that are ready to drill today,” said Steve Lucado, chairman at Trans Energy. “Frankly, that’s a lot in the Marcellus.”

Lucado said these locations represent less than 50% of what the company thinks its current acreage position can generate. Trans Energy controls additional, partially leased acreage and is currently acquiring additional new leases to fill in its position. These new and partial leases could provide the partnership 10,000 additional acres, increasing Trans Energy’s total ready-to-drill locations to between 500 and 600.

But acreage is only half of the equation. Successful E&Ps need to be able to find and produce hydrocarbons. Enter Trans Energy’s JV partner, Dallas-based Republic Energy. Its technical team includes Dan Steward and Nick Steinsberger, members of the group that refined the method for combining hydraulic fracturing with horizontal drilling in the Barnett Shale while at Mitchell Energy Corp. during the 1990s.

“Our estimated ultimate recoveries, or EURs, are averaging more than 2 billion cubic feet per thousand foot of lateral length,” he said. “Marion County wells are outperforming Marshall and Wetzel--the nature of the wells is very attractive.”

EnerCom compared Trans Energy’s 90-day average IP rates to the recent Marcellus/Utica company IPOs. Trans Energy’s production results were on par given the high liquids component when compared to its gassier peer group.

“Wet gas wells typically don’t flow as high as dry gas wells, but the economics can be superior given the uplift in realized prices from the liquids,” he said.

Trans Energy will drill 19 gross horizontal wells in 2014 and plans to complete 15 wells before year-end. The company recently closed a $200 million credit facility with Morgan Stanley, of which $102 million was funded at closing to refinance the company’s existing debt and pay closing fees and expenses.

“This was a vital step in securing necessary capital to reach our operational goals,” Lucado said. “Of course, like our peers in the Appalachian Basin, we’d much rather be putting capital to work in an environment with higher regional commodity prices.”

Natural gas hub prices in the Northeast have been trading at a discount to Henry Hub since the end of March 2014 in part due to growing Marcellus supply and cooler-than-normal summer temperatures. But even at $3.50 per million British thermal units, Trans Energy can still generate internal rates of return of 35% to 45% from its Marcellus wells.

Dividend yield

Net income and free cash flow are almost unheard of among small-cap E&Ps, but Evolution Petroleum Corp.’s Delhi Field in northeastern Louisiana has made generating positive earnings and returning free cash to shareholders a reality.

“We are not your typical oil and gas com- pany by any stretch of the imagination,” said Bob Herlin, CEO of Houston-based Evolution. “We don’t employ financial leverage and we have a very attractive yield (3.5%), compared to other income sources available to investors.”

Evolution’s Delhi Field is a tertiary CO2 flood project in northeastern Louisiana operated by Denbury Resources. The 65% developed project is an attractive continuing investment opportunity for Evolution because of relatively low future capital requirements expected to result in significant production increases. Evolution profits from Delhi in two ways--a 7.4% royalty interest in the field and a 24% reversionary working interest that is expected to take effect later this year.

“Our Delhi asset is going to be a substantial source of cash flow for us for the rest of its 40-year life,” Herlin said.

According to EnerCom’s proprietary E&P database, Evolution’s capital efficiency ratio is 1006%, meaning every dollar invested at Delhi produces $10 of EBITDA, net to the company.

“What’s quite interesting is that if the num- bers hold up as we expect, our PV-10 at Delhi is going to increase through the rest of this decade while we reap substantial net cash flow,” Herlin said. “Which is interesting because the remaining capital expenditures are much less than what’s been spent.”

Herlin said an important catalyst is on the horizon for Evolution at Delhi--its 24% working interest is expected to revert this fall, meaning more exposure to the project.

"With reversion occurring this fall, our revenues will more than triple on a monthly basis,” he said. “Cash flow will be doubling, and that has a big impact obviously in the way the company looks in its liquidity and options going forward.”

In addition to returning cash to shareholders, Herlin said the company has been investing in its proprietary Gas Assisted Rod Pump (GARP®) technology to bring marginal wells back to life for its own account and for customers. The GARP® technology extends the life of depletion drive horizontal and vertical wells experiencing loading issues, with the expectation of recovering an additional 15% to 35% of cumulative recovery at a cost less than $10/boe.

“So far, all of our installations have been in the older Giddings Field where horizontal drilling began, simply because the technology is intended for good wells that are now marginal due to loading issues,” Herlin explained.

“But we do expect to be able in the next year to start deploying our GARP® technology in other fields based on the conversations we’ve had to date with other operators.”

GARP® is expected to have a material impact on Evolution’s cash flows by 2015 and become even more impactful in 2016. “We believe GARP® has a potential approaching the Delhi level and similarly, as efficient a capital investment return,” Herlin said.

Brian R. Brooks is an associate director at EnerCom Inc. with more than five years’ experience providing strategic investor relations consulting to global E&P and oil service management teams.

Disclaimer: This article is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned here. It was prepared for general circulation and does not provide investment recommendations specific to individual investors.

Comments