Ready To Move The Needle

Time flies when you’re having fun. EnerCom will host the 20th edition of The Oil & Gas Conference® in Denver this August. A lot’s changed over the past 20 years, but one thing’s stayed the same: Investors are always looking for interesting investment ideas. At all points of the commodity cycle, investors favor companies with Tier-One acreage, strong balance sheets and operational excellence. And in the current commodity environment, investors prefer a well-positioned company that can take advantage of near-term catalysts on the horizon. Here is a short list of well-positioned companies with unique strategies and opportunities that fit that description.

“We take a long-term approach to the oil and gas business, and owning mineral rights provides us a variety of options,” said Michael Coffman, president and CEO of Panhandle Oil and Gas Inc. Right, Panhandle senior vice president and COO Paul Blanchard said the royalty ownership advantage boosts rate of return in its Fayetteville Shale holding.

A twist on ‘unconventional’

Panhandle Oil and Gas Inc. is considered an unconventional company—but not because of the way it drills or completes oil and natural gas wells.

While the company takes a conventional approach to the nonoperated business model by purchasing working interest with some of the nation’s top oil and gas companies, what’s unconventional is that in many cases Panhandle owns its mineral rights.

“We take a long-term approach to the oil and gas business, and owning mineral rights provides us a variety of options,” explained Michael Coffman, Panhandle’s president and CEO. “We can lease our minerals to the operator, or other party interested in drilling or participating in a well that is on the drilling unit. We can take a royalty interest in the well and potentially get a lease bonus payment. Or, we can participate with a working interest to receive a larger share of revenues generated from the well’s oil and gas sales.”

A simple example—say an operator owns 5% working interest in a well—means the operator would have a 4% net revenue interest after backing out the royalty payment. Panhandle, having the same 5% working interest, would have a 5% net revenue interest as the royalty owner. In this example, Panhandle would realize a 20% lower finding cost than the operator.

Even if the company decides to participate with a working interest in a well, Panhandle receives the royalty interest, free of charge. And, because Panhandle, as a nonoperating partner, isn’t obligated to share the geologic and geophysical costs, engineering cost and other prospect costs with the operator, the well economics are further improved.

“We’re only responsible for the actual cost of the well. This gives us a higher rate of return on our investment than the operator who has to go out and lease minerals to have the right to drill,” he said. “The royalty ownership ultimately gives us a lower finding cost and higher returns than our partners.”

Panhandle Oil and Gas’s senior vice president and COO Paul Blanchard said in places like the Fayetteville Shale, where its owns about 10,000 net mineral acres, the company could realize a rate of return as much as 69% higher than a typical working interest owner..

Panhandle, in business since 1926, was fortunate enough to purchase its legacy mineral positions before prices skyrocketed. The company’s average cost per mineral acre is approximately $90.

“We own the mineral rights of 255,000 acres, almost 400 square miles, across 10 states—the majority of which is not currently leased or held by production,” said Blanchard. “Approximately 72% of our revenue comes from our nonoperated working interest positions and 28% comes from our royalties.”

The company is not immune to hurdles other operators and nonoperators face, however. Quality rock is the key to success for any company. Looking at Panhandle’s portfolio, it is active in the nation’s most economic plays—the Cana Woodford, Scoop, Fayetteville and Eagle Ford.

Given the wide variety of options Panhandle has to make money, its superior returns, low debt and operating footprint, the company is well-positioned to weather the current commodity cycle and come out stronger than it was before.

“We are seeing similar initial production rates in the Lower Spraberry, but a shallower decline curve than in the Wolfcamp,” said Fred Callon (top), chairman and CEO of Callon Petroleum Co. Callon CFO and treasurer Joe Gatto, above, said the company is positioning for beyond 2015.

A true growth story

Oil veterans will tell you to drill your best well first.

Callon Petroleum Co. is following suit by allocating more capital to its most profitable project, the Lower Spraberry interval in the central Midland Basin region of the Permian Basin.

It’s tough to question the company’s decision. Callon reports its Lower Spraberry horizontal wells generate 55% internal rates of return (IRRs) at a realized oil price of $55 per barrel. Callon’s deeper Wolfcamp horizontal wells generate IRRs of 35% using the same price deck.

Since 2012, Callon has drilled more than 60 horizontal wells in the central and southern Midland basin, predominantly targeting the Wolfcamp Shale. Only recently, the company reallocated budget dollars to its Lower Spraberry well locations, driven by the play’s robust project economics, which have been enhanced by a 30% reduction in well costs.

Callon’s operational capital budget for 2015 is $160 million to $165 million, and includes plans to drill 13 Lower Spraberry wells, 19 Wolfcamp B wells and three additional wells targeting the Wolfcamp A, Middle Spraberry and Cline/Wolfcamp D. In 2016, Callon expects to allocate an increasing proportion of its capital budget to the Lower Spraberry, which is currently expected to account for more than 60% of wells drilled under the company’s current two-rig program.

“We are seeing similar initial production rates in the Lower Spraberry, but a shallower decline curve than in the Wolfcamp,” said Fred Callon, chairman and CEO of Callon Petroleum. “Combine that with a 30% reduction in well costs and we’re able to generate impressive results.”

Lower commodity prices recently prompted the company to drop one of its Permian Basin drilling rigs. Now, Callon will run two rigs for the remainder of 2015 as it remains focused on the balance sheet and targets cash-flow neutrality in the second half of 2016.

“It’s not about 2015, it’s about positioning our company for the future,” said Joe Gatto, Callon’s CFO and treasurer. “We dropped a rig and reduced our 2015 capital budget by 25% to more closely match our expected cash flow, but we’re still maintaining solid operational momentum in the business and positioning Callon for additional growth opportunities.”

Callon is expected to expand total production to an average 9,050 barrels of oil equivalent per day (boe/d) in 2015, an increase of 60% from the prior year. The company’s growth target far exceeds most, if not all, of its Permian Basin peer group. Looking forward to 2016, and assuming no increase in the current pace of drilling activity, the company expects its operating cash flows to match capital expenditures while delivering double-digit production growth over 2015 levels.

If organic growth wasn’t enough, Callon is well-positioned to take advantage of other growth vehicles as well.

“Our March 2015 equity raise brought $65 million in proceeds, and we have $215 million in liquidity on our bank revolver,” explained Gatto. “This allows us to stay flexible on the operations front, and pursue attractive bolt-on acquisitions as they arise.”

There’s no rush for Callon to do a deal, however, since the company has more than 500 identified drilling locations including only the horizontal zones that are currently producing on its acreage.

That equates to an inventory of approximately 20 years at today’s activity level. This inventory grows to more than 1,000 locations and almost 40 years when including additional zones that have been drilled by offsetting operators, including the Middle Spraberry and Cline/Wolfcamp D, which Callon will be drilling later this year.

Combining this deep well inventory with its seasoned operations team, it is well-positioned to continue its growth trajectory through the current cycle and deliver sustainable returns for the long-term.

Dividends, share repurchases, growth

Evolution Petroleum Corp. is not your typical E&P. The company is debt-free, pays a 2.8% dividend to common shareholders, has reported positive annual net income since 2012 and has several near-term growth catalysts on the horizon.

Evolution’s foundation producing asset is Delhi Field, a tertiary CO₂ flood project in northeastern Louisiana operated by Denbury Resources. The 66% developed project is an attractive continuing investment opportunity for Evolution because of relatively low future capital requirements that generate significant cash flow.

“Delhi is our primary producing asset, and we profit from it in two ways,” said Randy Keys, Evolution’s president and chief financial officer. “We have a 7.4% royalty interest in the field and a 23.9% reversionary working interest that went into effect in November 2014, which combined give us an aggregate 26.5% net revenue interest in the field.”

The company’s working interest reversion in November 2014 more than tripled its net production overnight, but the event was overshadowed by the rapid decline in oil prices during the fourth quarter of 2014.

Despite the commodity price decline, Keys and the team are finding new ways to reinvest cash and return free cash flow to shareholders.

“Denbury, the operator, is embarking on a new $100 million NGL plant at Delhi that’s expected to be operational by the summer of 2016,” said Keys. “Our share of the project is $24 million, which will be split between calendar 2015 and the first part of calendar 2016.”

Even at today’s prices, the plant is expected to increase net cash flow by as much as 50%, making the new gas plant a significant event for the company and its shareholders. The company is one of a handful of independent E&Ps that is generating positive free cash flow, and management has proven to be shareholder friendly, employing several methods to return cash to shareholders.

For example, in May 2015, Evolution implemented a $5 million common stock repurchase program to return cash to shareholders in an opportunistic manner.

“Since there is no time limit on the repurchase program, we can buy our stock when we believe it’s trading below its fair value,” he said. “And to the extent we can buy our stock back at a discount, it’s more accretive than a dividend.”

Since its founding, Evolution has maintained a conservative financial policy, and unlike most E&P companies is debt free with no borrowings on its $5 million revolving credit facility. The company’s steady cash stream combined with its strong balance sheet affords Evolution the ability to take advantage of new opportunities in the current commodity environment.

“We’re fortunate to have excellent near-term growth from our existing assets, with fairly modest capital requirements. But we are also looking at other transactions to add to the long-term growth of the company,” added Keys.

Newly public

Yuma Energy Inc. will celebrate its first full year as a publicly traded company in 2015. The company merged with Pyramid Oil Co. in September 2014 whereby it went public to help strengthen its focus on conventional and unconventional oil plays and to accelerate growth of its production and reserves.

“Our strategy is to leverage extensive 3-D seismic data to establish prospects in onshore liquids-rich projects with high-impact opportunities,” said Sam Banks, Yuma’s president and CEO. “We are focused primarily in the Gulf Coast and are targeting the Austin Chalk, Tuscaloosa and Wilcox, as well as multiple horizon prospects in our Amazon 3-D shoot.”

The company may be new to investors, but Yuma’s been exploring and producing oil and gas since 1983. It has amassed more than 75,000 net leasehold acres in three different states and has partnered with some of the top E&Ps in the industry to develop its discoveries.

One of Yuma’s strengths is its ability to turn exploration prospects into development projects.

“Since 1993, we’ve had a 78% drilling success rate on our proprietary 3-D projects in the Gulf Coast thanks to our strong geotechnical team,” said Banks. “Our ability to organically generate prospects and partner with industry partners is what sets us apart from many of the other E&P companies.”

Yuma uses a balanced portfolio approach with a mix of high-impact opportunities and lower-risk development wells to grow production and reserves. The scale of its working interest varies by each prospect, as the company aims to retain a high percentage of its development projects while promoting and partnering a piece of its working interest on its higher-risk exploration prospects.

“To the extent we can buy our stock back at a discount, it’s more accretive than a dividend,” said Randy Keys, Evolution Petroleum Corp.’s president and CFO.

“Historically, we have been very successful in taking our exploration success and turning it into cash flow,” Banks explained.

Production in first-quarter 2015 averaged about 1,774 boe/d and Yuma’s total proved reserves are 19.9 MMboe, according to an independent study by Netherland, Sewell & Associates. Approximately 70% of its reserves are liquids.

Yuma’s near-term focus is on its onshore Louisiana properties, where it has had tremendous success in finding and developing conventional onshore oil fields.

For example, in the Amazon project, Yuma recently drilled its Anaconda prospect and found more than 90 feet of pay from five different sand packages. The company was able to use legacy production data and its proprietary 3-D seismic over the area to establish a number of prospects to drill. To date, Yuma has identified eight leads and prospects to drill from the 3-D which could be meaningful cash-flow generators.

Also, it has an established play in Louisiana targeting the Austin Chalk at its Masters Creek Field, where more than 140 wells have been drilled. Yuma has identified some 67 operated proved undeveloped locations there over its nearly 70,000 net acres; future infill locations are expected to result in well recoveries of 500 to 600 Mboe.

“Louisiana is a great place to find oil and gas,” explained Banks. “Our production and future growth is supported by existing infrastructure and we receive Louisiana Light Sweet pricing, which currently trades at a premium to West Texas Intermediate prices. We are excited about the future and look forward to continuing to grow the company in the coming years.”

Brian Brooks is an associate director and Aaron Vandeford is a director with EnerCom Inc., which produces annual oil and gas investment conferences in Denver and San Francisco, the former this month.