UPSTREAM NEWS

Anadarko to acquire Freeport McMoRan GoM assets for $2B

Anadarko Petroleum Corp. has entered into a definitive agreement to acquire the deepwater Gulf of Mexico assets of Freeport McMoRan Oil & Gas for $2.0 billion.

"We expect these acquired assets to generate substantial free cash flow, enhancing our ability to increase US onshore activity in the Delaware and DJ basins. Our current plans are to add two rigs in each play later this year, and to increase activity further thereafter, with an expectation of more than doubling our production to at least 600,000 BOE per day collectively from these two basins over the next five years. This increased activity would drive a company-wide 10% to 12% compounded annual growth rate in oil volumes over the same time horizon in a $50 to $60 oil-price environment, while investing within cash flows. The company's Gulf of Mexico position, with the addition of these properties, will have net sales volumes of approximately 155,000 BOE/d, comprised of approximately 85% oil," said Anadarko chairman, president and CEO Al Walker.

With the deal, Anadarko increases its working interest in Lucius from 23.8% to 49%.

"At first glance, Anadarko's $2 billion Gulf of Mexico acquisition may leave investors puzzled given the relative unattractiveness offshore assets present against US onshore. However, upon seeing Anadarko's intention to plow incremental cash flow into Delaware and DJ Basin activity, we are confident that the deal will prove accretive," noted Raymond James analysts following the announcement.

And, despite the company's public offering of 35 million shares (5 million share greenshoe) to raise approximately $2.2 billion to fund the acquisition, the company's balance sheet "remains intact," the analysts said, pointing to Anadarko's stated intent to divest additional assets to the tune of $3 billion total in 2016.

Apache Discovers New Play In Southern Delaware Basin

After more than two years of geologic and geophysical work, acreage accumulation, and testing and delineation drilling, Apache Corp. confirmed the discovery of a significant new resource play, the "Alpine High." Apache's Alpine High acreage lies in the southern portion of the Delaware Basin, primarily in Reeves County, Texas. The company plans to initially target the wet gas windows of the Woodford and Barnett and later plans to test the oilier Wolfcamp and Bone Spring formations.

Highlights:

• Apache has secured 307,000 contiguous net acres at an average cost of $1,300 per acre.
• Alpine High has 4,000 to 5,000 feet of stacked pay in up to five formations.
• 2,000 to more than 3,000 future drilling locations have been identified in the Woodford and Barnett formations. Initial estimates for the Woodford and Barnett zones indicate a pretax, net present value range of $4 million to $20 million per well, at benchmark oil and natural gas prices of $50/bbl and $3/Mcf, respectively. Expected well costs in development mode for a 4,100 foot lateral are estimated to be approximately $4 million to $6 million per well.
• Apache has drilled 19 wells in the play, with nine currently producing in limited quantities due to infrastructure constraints.

2016 capital guidance update

Apache is increasing its 2016 capital spending by approximately $200 million for the year and raising its full-year capital guidance to approximately $2 billion. Capital spending on the Alpine High play in 2016 will represent more than 25% of Apache's total capital spending program.

Seaport Global Securities calls the announcement "the Permian unveiling we've been waiting for." Noting it had expected an unveiling of wildcatting results, the analysts said "the scale the scale and associated economics" of the Alpine High discovery come as a surprise. While only in the early drilling stages, the preliminary economics look encouraging. "At $40 oil and $2.50 gas prices, BTAX RORs range from 30%-250%+ and per well PV-10's clock-in at $2MM-$15MM, and breakeven gas prices are pegged at <$0.10-$0.60 (predicated on $40 oil prices)," the analysts detailed.

Development timeline

Over the next year and a half, delineation efforts in the play are expected to continue with a 4-5 rig lease retention program. Beyond that, Apache currently envisions a $600 million to $800 million capital program in fiscal year 2017, including infrastructure. Looking forward, noted Seaport Global Securities analysts, Apache may look to monetize non-Alpine High Permian acreage.

Oil price downturn proves less is more for explorers

New research from Wood Mackenzie indicates that the oil and gas industry is poised to emerge from the slump leaner, more efficient, and more profitable.

Dr. Andrew Latham, vice president of exploration research at Wood Mackenzie, said: "Our research shows that a number of things needed to, and are, changing. One positive side effect of the downturn that we have seen is that the majors have changed the way they approach exploration, leading to improved returns, even at lower prices."

He adds: "The new economics of exploration mean that rather than pursuing high-cost, high-risk exploration strategies - elephant hunting in the Arctic, for example - the majors have become more conscious of costs. Smaller budgets have required them to choose only their best prospects for drilling, including more wells close to existing fields. The industry now has in prospect a different - and potentially more profitable - future."

In the report, Wood Mackenzie notes that the majors invested US$169 billion in exploration during the period analyzed, adding a total of 72 billion boe to their resource base. Of this, 25 billion boe comes from unconventional plays. Resource discovery costs for the period averaged US$1.78/boe. Returns over the period were not optimal, with returns of just 6%, versus an industry average of 10%.

However, Wood Mackenzie notes that the majors moved quickly in 2015 to improve weak exploration returns. Steep cuts in exploration spending for the year have forced high-grading, which has led to enhanced prospect quality. Unconventionals are becoming increasingly important, attracting 15% of the majors' exploration spend and outperforming returns from conventional exploration since 2013.

Good conventional exploration volumes, together with large adds from unconventionals saw the majors add resources well ahead of the volumes they produced every year from 2011. Resource discovery costs also fell, with the lowest costs recorded in 2015.

The report notes, however, that conventional exploration's role in reserves replacement is set to diminish. Other renewal options - from unconventionals, discovered resource opportunities, enhanced recovery techniques and M&A - are likely to prove key to future reserves replacement.

Dr Latham says: "The early indications are that the majors are now getting the exploration economics right. Their exploration spend halved in 2015 versus 2014, with spend per well drilled falling to levels not seen since 2008. However, there has been a shift in ambition. Companies are no longer trying to fully replace production via conventional exploration, as they used to. Now their reserves replacement will also require inorganic, brownfield or shale investments. Exploration has become incremental.

"Another big factor is gas - companies are not replacing volumes in the same ratios as their production, or in the same way. Discoveries break down to about one-quarter oil and three-quarters gas, while global production is currently nearer two-thirds oil and one-third gas. The future will become steadily more gassy."

OGFJ reached out to Wood Mackenzie for additional comment.

"The cuts in spend per well made by the Majors are much deeper than those seen across the conventional exploration industry as a whole," noted Julie Wilson, research director, global exploration for Wood Mackenzie in an emailed statement, and there are a few contributing factors.

First, she said, the Majors "are more leveraged to deepwater than the wider industry. Here, we have seen steep discounts in rig rates as the rigs roll off contract, although some companies are still locked into long-term contracts. We have also seen heavy discounts in offshore seismic costs and other G&G services, which we include in our metric of spend per well."

Second, she offered, "the reduction in frontier and complex drilling and the move to lower-risk exploration and appraisal has had a greater impact on the Majors than other operators, again because of the Majors' greater exposure previously to higher-cost activity."

Finally, "the Majors had greater scope to become more efficient, given their scale and the fact that their absolute level of spend was far higher than most other operators'. The Majors have taken bold steps to become leaner and more efficient."

Overall, she said, "the reduction in oilfield service company prices probably contributes a little more than half of the reduction, while the rest of the reduction stems from a shift in type of E&A activity, and greater internal efficiency."

RBC producer insights from survey results

Royal Bank of Canada's (RBC) Greg Pardy recently provided a few energy insights. Here, an excerpt. Oil & liquids production growth has slid lower this year. When 2016 budgets were released for [RBC's] global coverage group last year, they collectively pointed towards 3% (600,000 bbl/d) of YoY oil & liquids production growth. Following the collapse in WTI prices to $26/bbl in February, this growth rate fell one-third to 2% (400,000 bbl/d) with [RBC's] April 2016 survey update. Based upon [RBC's] latest survey, YoY oil & liquids growth in 2016 has now fallen to just 0.5% (111,000 bbl/d). This follows staggering production growth of 9% (1.8 million bbl/d) for our coverage group in 2015-fuelled by years of $100+ Brent prices. While E&P companies under [RBC's] coverage account for production declines of 4% (308,000 bbl/d) in 2016E, the integrated oils are showing output growth of 3% (419,000 bbl/d)-fortified by longer cycle-time projects.

SURMONT RECEIVES APPROVAL OF APPLICATION FOR WILDWOOD OIL SANDS PROJECT

Surmont Energy Ltd. noted that the Lieutenant Governor in Council of the Province of Alberta, Canada, has issued an Order dated September 15, 2016, authorizing the Alberta Energy Regulator (AER) to issue approval of the project scheme application for the company's 100%-owned 12,000 b/d Wildwood oil sands project.

The Wildwood oil sands project location is about 65 kilometres south of Ft. McMurray, Alberta. The recently received approvals are valid for production of up to 12,000 b/d of bitumen from a northwest portion of Surmont's Wildwood leases. The company assesses the Wildwood leases to be capable of future expansions to total production of 30,000 b/d. Future expansions would require additional regulatory approvals.