Description

Antero Resources (AR)

$40.34

Investment Summary

Antero Resources (“Antero”) is an independent gas-focused E&P operator with ~400,000 net acres in the Marcellus shale and ~150,000 net acres in the Utica shale. Over the past seven years, management has consolidated acreage in the Marcellus and Utica shales, two of the lowest cost basins in the world. The low cost nature of the acreage allows Antero to drill profitably even in less than $4 gas and ~$60 WTI.

After evaluating many energy names (services businesses as well as E&P names), we found Antero to be a notable exception: excellent management, terrific assets as well as a stock that is trading at a significant discount to NAV. Antero’s stock has been under significant pressure recently as spot and forward oil, gas and NGL prices have fallen. Note that 85% of Antero’s production and ~70% of EBITDAX are derived from natural gas rather than oil. The remaining 15% of production is predominantly NGLs, which are priced individually but essentially tied to oil prices over the long-run.

Antero owns non-E&P assets as well. In November 2014, Antero spun-off off Antero Midstream (“AM”), gathering and compression systems in the Marcellus and Utica, as an MLP. Antero currently owns 70% of Antero Midstream. Antero also currently owns 100% of a fresh-water pipeline distribution system that will likely be dropped down to AM, having recently received a favorable PLR from the IRS. Antero also has a portfolio of commodity price hedges from 2015 to 2021 worth ~$2.1bn at current prices.

Antero Asset Summary

·         Southwestern Marcellus proved and 2P reserves

·         Utica reserves and additional net resource

·         70% ownership of Antero Midstream – LP interest only

o   Gathering and compression midstream assets

·         Fresh water distribution midstream business

·         Hedge portfolio

The prospective return on Antero stock is compelling: ~50% implied return to NAV assuming a 10% discount rate. This valuation is based on currently leased acreage in the Marcellus and the Utica and does not give any credit for Antero’s acreage in the Upper Devonian and parts of the Utica shale. A number of seemingly likely outcomes could drive the prospective IRR notably higher including improved drilling techniques (longer laterals, more frac stages and more sand), lower drilling service costs (should commodity prices remain low and drilling activity in other basins continues to slow), increased value at AM through organic growth and acquisitions, opportunistic land purchases (and thus more drilling locations), increasing the number of rigs operated and wells drilled (pulls cash flows forward on high IRR wells), shift to ethane recovery (rather than ethane rejection, currently), including a value for Antero’s entire resource position (i.e. 3P+), potentially higher commodity prices, and any value-accretive M&A.

Business and Industry

Low Cost Producer: Antero has some of the best natural gas acreage in the world. The combination of low finding and development (F&D) costs along with liquids-rich (i.e. NGL) content combines for very attractive gas-drilling economics. In particular, Antero’s large acreage position in the Southwestern Marcellus generates single well IRRs between 14-55% (assuming the commodity price forward curve as of 12/31/14). Antero has prudently bought adjacent acreage to its existing land position, creating contiguous land blocks within the Marcellus and Utica. This allows for longer laterals as well as operational efficiencies which improve well economics.

Over the last 3 years, the gas production from the Marcellus and Utica shales has grown while production from all other U.S. basins combined has declined. Given the low costs in the Marcellus and Utica, this trend seems likely to continue. Over time, as the incremental supply available from the Marcellus/Utica decelerates while natural gas demand continues to grow (most notably from LNG exports), there is the prospect that natural gas prices are set by higher cost basins (>$5/mcf). Note that the price now is being set by a combination of the all-in costs of low cost basins and ongoing costs (excl. drilling costs) of higher cost basins. Should gas prices be set by the all-in cost of higher cost basins, Marcellus and Utica producers would receive windfall profits.

Low Risk Profile of Reserves: Shale rock is much more predictable than conventional drilling. Amongst the wells drilled in the Marcellus, Antero has drilled zero dry holes. The Marcellus/Utica is already producing ~25% of the U.S. gas supply. While new, the Marcellus is far from an unproven resource. Irrespective of the risk profile of a potential well, wells that are not planned to be drilled within the next 5 years cannot be booked as proved reserves (PDP or PUD). These reserves are booked as probable (or possible) reserves. Note that Antero’s “exploration” spending is very low. Exploration expense in 2014 was $28mm.

Firm Transportation Secured: Based on the supply of gas and transport infrastructure in a particular basin (or region of a basin) as well as the demand for gas in a particular region, regional gas markets sell at a premium or discount to Henry Hub (NYMEX) gas. Therefore, Antero’s revenues are tied to regional gas prices rather than directly to NYMEX. Management has locked up firm transportation agreements to multiple markets in order to minimize direct basis risk to one particular region as well as provide optionality should one region have particularly high demand.

Unlike some E&P companies in the region, Antero has secured more than enough takeaway capacity and those deals expire in 2017-2025. Other E&P companies such as Southwestern, which recently bought Chesapeake’s acreage in the Marcellus, are having short-term gathering and transportation challenges and can only run 1-4 rigs this year. Antero has enough capacity to run at least 14 rigs in 2015 and even more rigs in subsequent years. One downside to securing long term transportation is there are volume minimums which must be fulfilled. If Antero’s production does not meet volume minimums, the company can buy 3rd party gas to fulfill its volume commitments or sell the capacity to other E&P producers. Antero has been successful in minimizing the costs related to unused capacity or marketing expense. Q1 2015 marketing expense was $0.12 per mcfe compared to 2015 guidance of ~$0.25 per mcfe.

Large and Attractive Hedge Book: Because of the high decline curves and increase in U.S. onshore drilling, a significant portion of U.S. natural gas production each year needs to be replenished by new wells. The decline curves are so steep that most of the value of a well comes from the first 5 years of production although the wells will likely produce for 30-40 years. This decline curve allows producers to lock-in costs (transport and drilling) while also hedging commodity prices for the first few years of drilling. Approximately 25% of Antero’s Marcellus wells’ production comes in the first 2 years, and 40% in the first 5 years. This allows producers such as Antero to significantly mitigate commodity price risk if they so choose, de-risking the value of the company’s resource/assets.

Antero has hedged a significant amount of its production from 2015 to 2021 and has perhaps the largest hedge book amongst all E&P companies. Currently, Antero’s hedge-book is worth ~$2.1bn. Note the company largely hedges natural gas but has started to hedge its NGL and oil production as well. Antero has hedged 94% of 2015 production and have similar volumes hedged for 2016 to 2021. Antero’s hedge contracts are with large, reputable banks including BNP, CS, JPM, Barclays, Citi, Wells, DB and Toronto Dominion. Counterparty risk seems low.

Low Financial Risk Profile:  Antero has and continues to secure very attractive financing. Antero’s borrowing base (i.e. size of the credit facility) is re-determined semi-annually and is based upon cash flows from proved reserves under current commodity price conditions while also taking into account commodity price hedges. Antero’s LOC is L+ 150 bps to 250bps depending on its borrowing base usage  with a maximum drawdown of $4bn. It is worth noting that Antero’s borrowing base was reaffirmed at $4.0bn recently and lender commitments under the facility actually increased by $1.0bn, even in today’s pricing environment. The average rate on this facility was 2%. Note that the LOC is funded by a syndicate of 16 banks.

Additionally, Antero has secured long-term financing through several senior notes offerings with rates ranging between 5.1% and 6.0%. Antero’s LOC matures in 2019 and the earliest maturity of senior notes occurs in 2020. Note that none of Antero’s debt tranches has debt/EBITDA covenants and the company has significant room over its 2.25x interest coverage covenant. On March 3, 2015, Antero announced the pricing of a $750mm of 5.625% senior unsecured notes due 2023 at par.

Antero currently has net leverage of 3.2x which is higher than other gas E&P companies. However, given the hedged production and low risk nature of its operations, we do not see Antero experiencing any trouble with its debt load. Antero has positioned itself very well to benefit from using attractively priced debt to aggressively increase its production at attractive IRRs.

High Demand for U.S. Natural Gas Volumes: Increased regulations and low gas prices are causing many coal-fired plants in the U.S. to become uneconomic. The most significant recent legislation is MATS (Mercury and Air Toxics Standards), which limits power plant emissions of particular toxins – mercury, arsenic and metals. Compliance with MATS is required this year. Due to the high costs and time required to upgrade non-compliant coal plants coupled with already low coal plant margins and low gas prices, gas-fired capacity is more economic vs. re-tooling existing coal plants.

LNG exports are likely to drive a significant increase in natural gas demand over the coming years. Currently, approximately 9 Bcf/d of incremental demand is expected by 2020 with the first export facility coming online in 2016. This compares to total current gas supply of approximately 79 Bcf/d. Some industry analysts assume that over the next 10 years, the U.S. may export 15-30 Bcf/d of natural gas.

Management and Private Equity Owners

Antero’s management has had a track record of success. Paul Rady has served as Chairman and CEO of Antero since May 2004. Rady began his career with Amoco where he served 10 years as a geologist focused on the Rockies and Mid-Continent. In 1990, Rady was initially recruited as Chief Geologist at Barrett Resources, and then served as Exploration Manager, EVP Exploration, President, COO and Director and ultimately CEO until 1998. During that time, Barrett was a pioneer in natural gas development in sandstone formations through hydraulic fracturing in western Colorado’s Piceance Basin before being purchased by Williams in 2001 for $2.5 billion. After leaving Barrett Resources in 1998, he formed Pennaco Energy with Glen Warren (Antero’s current President and CFO). Rady and Warren led Pennaco as it aggressively grew from a small acreage holder in the Powder River Basin coal bed methane play in Wyoming into one of the largest leaseholders in this play. In February 2001, less than three years after its inception, Pennaco was sold for $500 million in cash to Marathon.

In 2002, with the backing of Warburg Pincus, Yorktown Energy Partners and Lehman Brothers Merchant Banking, Rady and Warren formed Antero Resources (the predecessor company) and focused on the Barnett Shale in North Texas. Antero became the second-largest producer in the Barnett and sold its assets to XTO Energy in April 2005 for $685 million in cash and stock.

Less than two years later in 2007, Rady and Warren launched the second (and the current) Antero Resources and received ~$1.4 billion from the same investors: Warburg Pincus, Yorktown Partners and Trilantic Capital Management (formerly Lehman Brothers' merchant banking business). Initially, Antero Resources was focused on developing properties in the Arkoma Basin of Oklahoma and the Piceance Basin of Colorado. However, Antero Resources divested its Arkoma and Piceance Basin properties and quickly redeployed that capital into adding acres of leasehold in the Marcellus and Utica shales, focusing on the development of liquids-rich natural gas.

Rady manages the business with a keen eye toward risks by ensuring takeaway capacity, hedging regional gas price exposure, contracting for capacity such that ethane rejection is an option, hedging NGLs and terming out debt with essentially no covenants or maturities within the next 4-5 years, while also decisively taking advantage of the opportunities in front of him by aggressively leasing up the Southwest Marcellus before others had figured out the pressure issues, utilizing cheap debt appropriately to maximize NAV/share growth and drilling and hedging at a rapid pace as a long as IRRs are attractive. Rady has sold two of his previous companies for nice gains, and he has the vast majority of his net worth tied up in Antero (although the exact figure isn't clear because the private equity / management ownership split has not been solidified yet).

Private equity owners and Antero management own Antero Investments (AI), not Antero shares. AI owns 72% of Antero shares, yet AI also owns 100% of AM’s general partner (and associated IDRs). While this structure is suboptimal and potential conflicts of interest exist, this is unlikely to have a meaningfully negative impact on Antero shareholders. First, the NAV of Antero is 5-10x greater than the value of AM’s GP. It would make no sense for management to significantly erode value at Antero by uneconomically growing production at AM – Antero is where the primary source of value lies for AI, and Antero owns 70% of AM, too. Second, the contracts with AM are already set in place for 20 yrs. While perhaps these contracts could be changed, it seems unlikely that this will happen. Third, if Antero Midstream’ s GP becomes very valuable, Antero’s production growth must be very strong, so Antero will likely have appreciated in value as well.

Valuation

Assuming the current commodity price forward curves, Antero trades at a 50% implied return to NAV based on conservative modeling assumptions and taking into account the value of Antero’s hedges. Note that a NAV analysis is very sensitive to reasonably minor changes in operating assumptions and commodity prices, especially at lower gas prices. Plus or minus 2% annual changes in drilling costs in the first 10 years of the model can change the implied return by ~15%.

NAV Breakdown

·         Marcellus Shale - $10.3bn

·         Utica Shale - $2.0bn

·         Upper Devonian Shale, Utica Net Resources - $0bn

·         Drilled Locations / PDP - $2.2bn

·         Market Value of AM - $3.0bn

·         Water Distribution Systems - $1.5bn

·         Hedge Portfolio - $2.1bn

·         Net Debt (Excluding Consolidated Cash At AM) – ($4.1bn)

·         NAV of ~$17bn ($61/share) vs Current Market Cap of ~$11.3bn ($40/share)

Current Commodity Price Forward Curves

In our base case, we assume Antero will maintain the average number of rigs in operations at 14 for 2015 and 2016 and a ramp to 22 rigs in 2019+. A long term low gas price environment can force Antero to reduce its capital expenditures and rig count which will have a significant adverse effect on its NAV. We assume $0.25 - $0.42 price differential for gas based on the Antero’s transportation and sales portfolio and the forward pricing in regional gas markets. We also assume NGLs are priced at 50% of WTI. While one can argue that over time, the price differentials should decrease as further infrastructure is built out and the gas market becomes more efficient, we assume $0.25 price differential for gas after 2018 throughout our model.

Note that our NAV does not factor in increased productivity per well (i.e. improving well economics from technological advancements). Instead, we assume ~15% cost reduction in drilling in 2015 and 2016 cumulatively and hold drilling costs flat for the next 10 years, and then increase drilling costs in-line with assumed price inflation (2% annually). If Antero’s drilling costs decline even more in-line with oil service costs, which seems likely as drilling activity in a number of basins slows due to the recent plunge in oil and gas prices, that would be beneficial to NAV.

Note our NAV ascribes no value to Antero’s Upper Devonian acreage (which includes 4.6 Tcfe and 1,116 undrilled locations) and no value to Antero’s dry gas net resource acreage in West Virginia/Pennsylvania Utica shale (which includes 11.1 Tcfe and 1,616 undrilled locations). These assets may be quite valuable in the future. We also do not assume a shift to ethane recovery or value-accretive land purchases, both of which would increase NAV.

Note that in a commodity price case of $4 gas and $65 WTI, the implied return is 68% with all other assumptions remaining the same.

Risks

Low Commodity Prices. There is no way around that this investment is commodity-price related. In a sustained, long-term environment of $2.50 gas and $40 oil, this investment would lose money. Antero's hedge book and strategy, global low cost position as well as the fact that Antero will benefit from improved onshore shale drilling productivity (whereas offshore E&P cash flows would decline as improved shale drilling productivity drives down the breakeven commodity price) make Antero well-positioned to navigate through the inevitable downturns in commodity price cycles.

Increased Regulation. There is the risk that West Virgina, Ohio and Pennsylvania ban fracking although the probability of that happening seems low. However, drilling taxes in those states may increase.

Environmental Liabilities. For E&P companies, there is always the risk of environmental liabilities.

Lower Cost Basins. E&P companies could discover even lower cost basins than the Marcellus and Utica.

Catalyst

- Improved well productivity

- Decline in drilling costs

- Dropdown of water business to AM

- Opportunistic land purchases

- Further proving-out and developing total resource