It's Time to Sink or Swim for Offshore Drillers
The Macondo well incident will be imprinted in our minds for years to come about the dangers of offshore drilling.
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It's Time to Sink or Swim for Offshore Drillers
The Macondo well incident will be imprinted in our minds for years to come about the dangers of offshore drilling.
By Dave Forest, Oil & Energy Insider: Critical news for the Exploration & Production sector came this month. Not a new discovery. Not a drilling technique. It didn’t come from geologists or engineers.
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The One of the most critical pieces of news for the E&P sector came this month.
Not a new discovery. Or a high-impact drilling technique. In fact, this development didn’t come from geologists or engineers at all.
It came from a group of accountants.
Namely, mega-bookkeepers Ernest & Young. One of the leading firms globally in auditing and analyzing finances for oil and gas producers.
This outfit sounded a warning on the future of the E&P sector. Telling investors they need to beware of a silent killer that is stalking producers in some parts of the world. Places stock buyers should be looking at reducing their exposure.
The accountants also gave some hints on which E&Ps appear immune to this potentially company-ending issue. Ideas that suggest a certain group of investments in the oil and gas space are going to outperform significantly.
The issue driving this risk (and opportunity) comes down to one word: costs.
Ernest & Young looked closely at costs for the global E&P world as part of the firm’s annual “Global oil and gas reserves study”.
Their findings were astonishing.
The numbers left little doubt that costs in today’s oil and gas world are weighing on producers like never before. Production costs in 2012 rose 6% globally—driven by higher prices for labor and services.
Now, 6% isn’t a huge amount on its own. But numbers like this start to get worrying when you combine operating costs with other rising expenses for E&Ps—like finding costs, the amount paid by producers to discover and book in-ground oil and gas reserves.
Sifting through the data, E&Y found that finding costs are silently obliterating E&P profits. The cost to find a barrel of oil equivalent jumped nearly 30% in 2012, to $21.83 per boe from just $16.90 per boe in 2011.
On the back of all of these growing costs, the study shows that total E&P exploration and develop spending rose 20% in 2012. Over the last five years, global spending has grinded upward by an incredible 48%.
Here’s where these rapidly-inflating expenses get really worrying for investors: because E&P companies are no longer seeing the cash flow and reserves growth to support this spending.
Just look at the numbers. Combined oil and gas production globally rose by a meager 2% in 2012. With producers managing just a 1% increase in revenues from this output.
Reserves also aren’t growing much. Oil reserves globally bumped up by just 3% in 2012. Worldwide gas reserves actually dropped by 2% on the year.
Amid this stagnant growth, rising costs are hitting the bottom line hard. Worldwide after-tax profits for the E&P sector plummeted 16% in 2012, to $268.4 billion.
The Last Time This Happened, Stocks Plunged 40%
This story of flagging production and spiraling costs is all too familiar for anyone who’s been following another segment of the natural resource business lately—the mining sector.
Early in 2012, the CEO of major gold producer Newmont Mining, Gary Goldberg, sounded a warning on costs.
His cautioning sounded odd at the time. Gold was trading at a very reasonable price of $1,600 per ounce. There was a sense that producers were poised for big profits and future growth.
But Goldberg noted that in actuality, costs were silently killing the gold mining business. He pointed out that while the much-lauded rise in gold prices had upped bullion by about $1,000 per ounce over the previous decade, his company had seen its production costs rise by $900 per ounce during the same period. Essentially wiping out any profits—even at record prices.
These words proved prophetic. Less than a month later, softening gold prices cut the legs from under cost-weakened gold companies—with the AMEX Gold Miners Index losing 40% of its value in just three months.
The miners have seen little recovery since.
The E&Y study suggests a similar rot may be afoot in the oil and gas industry.
With all eyes fixed euphorically on high oil prices, few investors are noticing constricting production and reserves growth—not to mention contracting profits—from their E&P holdings.
But profits—not oil prices—ultimately drive share price performance. And the new study suggests that leading indicators on this front are pointed firmly downward. E&Y note that in places like the U.S., producers in 2012 actually spent more money than they made—with capital expenditures running 123% of operating profits.
The mining sector also saw such over-reaching prior to its crash. Producers spent more than they had on acquisitions and development. At the time, investors cheered the aggressive growth, believing that if you built it, rising profits would come.
But as it turns out, spending beyond one’s means always ends one way—big debts and empty treasuries.
These Places Might Be Safe Havens From Rising Costs
Should investors therefore abandon the oil and gas business ahead of a massive collapse in valuations for the E&P sector?
No—or at least, not all of it.
The E&Y study does provide a few positive indicators. Production areas outside of the U.S. seem to be enjoying lower costs—especially in Europe, where capital expenditures ran only 31% of operating profits in 2012. Globally, the average percentage of spending compared to profits came in at just 54%--much lower than the 123% seen in the U.S.
Investors may thus be served today by looking at oil and gas investments outside of “hot” shale plays in America.
But for those who still want to bet on the phenomenal upside of shale, a closer look at the U.S. E&P space shows some important regional variations.
We won’t get new numbers on reserves growth and associated costs until early 2014—when most producers file their year-end reserves statements. But another metric gives us a sneak peak at who’s hurting and who’s hurtling when it comes to costs these days.
The chart below shows percentage changes in unit operating costs for several U.S. producers during the first nine months of 2013, as compared to the same period of 2012. It’s obvious there’s a big spread—some firms are seeing costs soar, while others are actually enjoying lower costs per barrel of oil or mcf of gas than they saw last year.
The difference may have to do with the plays these producers are working in. All of these E&Ps are primarily focused in one or another of major U.S. plays in the Marcellus shale, Eagle Ford shale, Bakken tight sands or the shallow-water Gulf of Mexico. And as the chart below shows, when you break down operating cost changes by play, some big differences emerge.
A big revelation is that costs for Marcellus producers are actually going down. Likely a result of increasingly drilling productivity here that’s creating higher per-well output. It’s simple math—when you get more gas from the same well, operating costs stay more or less fixed. So unit operating expenses go down.
This jives with recent findings from the U.S. Energy Information Administration that show drilling productivity in the Marcellus has risen 30% so far in 2013.
By contrast, drilling productivity gains in older plays like the Eagle Ford have slowed—with that play showing just 5% productivity growth this year. The likely reason why producers here are seeing rising unit costs—as general inflation outpaces sluggish productivity improvements.
Aside from the explosive Marcellus, investors might also look to the more boring climes of the Gulf of Mexico—where costs have held steady so far in 2013. A result of this disregarded production area not seeing the elbow-to-elbow competition for services that’s driving up rates for onshore plays.
The warnings on rising costs thus may not be a reason for investors to abandon the E&P sector entirely.
Rather, they might be a prompt to do so for the plays most struggling with this growing issue.
source : oilprice.com
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Long gone are the days of easy money, so it seems. Junior energy companies are finding today’s capital to be more expensive and harder to access.
In the current market, juniors are fighting an ongoing battle just to balance sustainable growth, manage debt, and to compete with peers for dollars that just aren’t there. When assessing a junior, one must look at how they put their budgets together and maintain them if they’re to survive out there in the wild.
This isn’t a new phenomenon either, as a 2011 study of post-recession capital markets performed by the Society of Petroleum Engineers inferred that, “Upstream energy companies now compete not only for preferred access to the best new hydrocarbon resources but also for credit from capital markets.”
It’s time to point out the obvious. There’re not a lot of positive scenarios out there for these small caps.
The problem today is that many companies have to strap themselves in and take on debt, which puts them at great risk: Deliver or die.
The reality is that the rise of unconventional resource plays, along with the increased use of horizontal drilling and complex completions have driven prices through the roof. A company going to the street to raise $5-10 million for one horizontal well is really exposing itself. Even if they hit on their first well, the market can be unforgiving when a company comes knocking on the door of the coffers once again.
Lord help you if the well is a bust. When you’re a junior, you can’t bury the past behind 6 or 7 other wells with a huge capital budget. In reality they only raise a big enough budget for one high-cost well, and there’s no room for error.
The banks have also been unsympathetic, as the disposition market continues to dry up. Companies don’t have the opportunity they’ve had in the past to sell assets in order to get cash like they used to. That option is also closed.
So what’s a junior to do?
This is where it might be beneficial to look at two peer companies coming at the same problem with different methods, but similar strategies: Blackbird Energy [TSX.V: BBI] and Edge Resources [TSX.V: EDE].
Both are completely aware of the challenges ahead, and share roughly the same market cap while at the same time run programs consisting of lower-risk growth plans.
“This is quite frankly the biggest ‘show me’ market I’ve ever seen,” says Garth Braun, President and CEO of Blackbird Energy.
“If you can succeed in actually showing people your potential through your results, only then will you see movement. So you must show the investor that not only can you make them money, but that you have a suitable portfolio of assets and a stream of activity to come that you can sustain.”
Braun’s team is coming off of a very successful private placement capital raise that resulted in an oversubscription to the tune of $3.1 million. With a diversified asset portfolio that includes many (to steal a baseball analogy) singles and doubles on its low-risk Mantario properties, as well as a large land base with a high price tag within two areas of the highly sought after Montney play.
In order to keep up with his gameplan, Braun and his team intend to drill several of these low-risk Mantario wells over the next year. Given the examples led by their Mantario predecessors Rock Energy [TSX: RE], it’s plausible to predict that if Blackbird can repeat Rock’s successes they’ll be able to drill, complete and tie-in these wells at a cost of only $750,000 for production on average of 75 bbls/d each, picking up their production totals along the way.
But while Blackbird can easily afford to continue drilling these shallow conventional wells, it’s the big potential on their Montney real estate that has the potential to make the needle move. Surrounded in the Bigstone region by majors such as Kelt Exploration [TSX: KLT] and Delphi Energy [TSX: DEE], Blackbird knows that it’s sitting on some very valuable land that continues to grow in value as its neighbours drill.
Courting a major into a carried interest can only serve to help increase the value of the company going forward and production—all without having to take on the risk of going it alone. On the flipside, it would take the team a very long time to generate the kind of cash needed internally to take the higher risks necessary when elephant hunting in the Montney.
“The only way a junior can truly capitalize their program and fund their growth is through internal generation of cash,” says Brad Nichol, President and CEO of Edge Resources.
“Unfortunately, most juniors have to deal with Recycle Ratio, which is in a sense the profit to investment ratio. If you put a dollar in, how many dollars do you get out?”
Typically right now the average profit to investment ratio that companies are operating under is approximately 1.5. That means for every $1 they put into the ground, they get $1.50 out (over the life of the well).
“My profit to investment ratio is 3.5. I’m generating cash through investing into the ground and drilling wells that I know will generate much more cash then I put in,” says Nichol.
Much like Braun’s Mantario properties, Nichol’s Edge Resources is touting low-cost, low-risk production growth on its Eye Hill project. Both the Eye Hill and Mantario give each company the potential for pay out in roughly 6-8 months.
“I’m focusing on conventional shallow wells (as opposed to unconventional costly horizontal wells). With each one, I’m only risking $650,000 capital all in, and that’s not even the risk capital,” says Nichol. “That’s just the capital requirement to get me a producing well.”
“I’m spending less capital and getting a better result. I’m paying back the capital in 6 months or less, and I’m generating 3.5x the capital we put in. That’s the key to Edge Resources, and what makes us unique.”
Recent news from both companies has shown a different strategy in terms of raising money. Edge Resources has gone the debt route, while Blackbird went the equity route. The debt option was still open for Edge, perhaps because of the healthy recycle ratios, which don’t scare the bankers away from the teller window. For Braun’s strategy, there was still quite a bit of interest when he went to the market with some valuable additions to the company portfolio that lured in new investors (Disclosure: that includes this author on the most recent private placement).
“I’m not against debt if it’s in essence well serviced and I have ready access to the equity markets to replace it,” says Braun. “We felt we were at a point where in essence we originated all of our oil plays and now we’re focusing on drilling them up. It was premature for Blackbird to go and take debt on. It was offered to us but I felt it was too risky for our shareholders to be exposed to that kind of debt.”
“We wanted to drill up the assets and prove it. We felt there would be a material-value move to our company, and I wasn’t willing to take the risk on putting a date of failure on if I wasn’t able to raise equity. So with our private placement it does indeed cause some dilution, but the bonus is that I don’t have a proverbial Sword of Damacles in the form of a milestone date over my head. Instead, we worked to rally together a group of investors that wanted to invest in our company and see us grow through that investment.”
Blackbird’s most recent operational update hints towards a new milestone on Mantario. Production on it's A15-6 well has officially been announced, with results soon to come in the next 15 days. As well, the company picked up an additional 18 sections (11,520 acres) of P&NG rights in the Greater Karr area, all of which include deeper rights like the highly prospective Duvernay formation. Should Blackbird continue to drill Mantario while dangling the Duvernay, they should be able to continue to make their new set of investors happy.
By. G. Joel Chury of Oilprice.com
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Sometimes geography just works.
That’s certainly the case in North American natural gas markets today.
To the north you have America—a new natural gas superpower. So super that producers have cratered prices for their product amid a wash of new supply coming on from shale plays around the country.
And to the south there’s Mexico. The “lazy cousin” whose petroleum industry has squandered its cash (or had the cash squandered for it by the wider federal government). To the point where a lack of reinvestment in producing infrastructure has cratered production by 15% since 2008. At a time when politicians are desperate to move away from expensive oil-fired generation for electricity.
Sounds like a match made in Business School 101. The obvious solution to both problems being a few short miles of pipeline to redirect ample U.S. gas supplies south, and ample Mexican gas prices north.
But this is far from just a satisfying economics exercise. If U.S. natgas exports to Mexico can indeed be achieved at scale, it could represent one of the biggest investible opportunities of the decade.
“At scale” is exactly the plan right now. At least six new or expanded export projects are on the books, with capacity to send an additional 3.5 billion cubic feet per day of gas to Mexico. Doubling current export capacity.
These added flows could bring total US-Mexico exports to several billion cubic feet per day. Eating up 5 to 10% of total U.S. gas production. That’s a slug of new demand big enough to push prices higher quickly. Which would crate investment opportunities in both the commodity itself, and the shares of U.S. gas producers who would see profits soar.
It will thus pay to know if and when the Mexican export boom is going down. Which means watching a few key indicators—boxes that if ticked will tell us it’s time to go long gas and the U.S. E&P sector.
Below are four critical issues that will shape the fate of U.S.-to-Mexico gas trade—and signal when the time is right for this mega-trade.
Regulators approving export pipelines
One of the major questions around exports is the permitting process. Several new U.S. pipelines are needed to move gas to the Mexcian border for export—and those developments require regulatory approval. A step that is proving challenging for other export outlets like LNG.
But just last month, we got some positive indications on the permitting front. The U.S. Federal Energy Regulatory Commission (FERC) gave tentative approval to the Sierrita gas export pipeline in Arizona, being built by El Paso Natural Gas. FERC gave the pipeline a more-or-less clean pass—noting only a few environment issues that could be brought to “less-than-significant levels” through proper handling by El Paso.
Crucially, FERC avoided some semantic pitfalls that could have complicated the approvals process. There was some push for environmental approval to cover not just pipelines on U.S. soil but also end-use Mexican power plants taking gas exports. Such extra-territorial consideration seems odd, but it has happened.
FERC however, decided solidly against blowing up the scale of the Sierrita approval. The agency noted that, “There is no jurisdictional basis for the Commission to approve, mitigate or reject any of the Mexico facilities.” This greatly simplifies the permitting process. Setting the stage for easier approvals of additional export projects going forward.
Gas buyers getting testy
Environmental approvals are not the only part of the permitting process for would-be gas exporters. Firms building new export lines will also have to deal with potential objections from local gas users in the U.S.
That’s because FERC is also tasked with ruling on the need for export projects. Project operators must therefore make their case in demonstrating how their gas exports will help the overall market. The Commission will then have to decide if these projects are in the best interest of the American energy sector and the public.
A battle looks to be brewing on this front. This summer, one of the largest U.S. gas-fired power generators Calpine (NYSE: CPN) filed a motion to intervene in the approval of one major Mexican export project.
In filing the intervention, Calpine noted that “the terms and conditions for natural gas service to [Calpine] may be affected by the outcome of this proceeding.” Certainly true if a big rise in gas exports to Mexico triggers price increases—thus making Calpine’s fuel of choice more expensive, and reducing the company’s operating profits.
With gas-fired power growing rapidly in the U.S., such opposition could become a force to be reckoned with. In September, speakers from the power sector at the Marcellus Shale Coalition's Insight 2013 conference in Philadelphia noted that gas demand in the American power sector is likely to grow even faster than most experts are projecting. In fact, one consultant said that new environmental regulations in America have made natgas the “only new baseload option that is economically viable.”
This is likely to create a rapidly-growing lobby that doesn’t want to see U.S. gas go anywhere but into domestic power plants.
Building major pipeline arteries
Several planned export projects will tie into Mexican pipelines that don’t yet exist. This includes the above-mentioned Sierrita pipe, which is planned to connect with the Sasabe-Guaymas pipeline--a 338 mile pipe that will take gas to power plants near the towns of Puerto Libertad and Guaymas, located west of Chihuahua on the Gulf of California.
The only problem is that the Sasabe-Guaymas pipeline is currently only a concept. It’s supposed to be built by an affiliate of Sempra Energy.
While this line looks like it will go ahead (the tender is already complete), other key parts of the Mexican natural gas infrastructure are less certain. Earlier this month, the Mexican government released a tender for the 740 kilometre Ramones pipeline—designed to connect the new Sempra-built line further into the industrial heartland of north-central Mexico.
But the project fell over when only one company bid for the construction. This is a major set-back for a key part of Mexico’s gas infrastructure. The price tag for the project—at $3.3 billion—could make it tough for the government to go it alone without private-sector help. Thus endangering a key piece of the Mexican pipeline network—and raising the risk that new U.S. pipelines may end up being a “bridge to nowhere”.
Mexican demand growth actually appearing
Another key risk is whether Mexican gas demand will in fact materialize at all.
On the surface, the situation looks promising in this regard. Overall Mexican gas demand has been surging—nearly doubling over the last 15 years. At the same time, weak production has led to a gap between supply and demand of at least 500 billion cubic feet yearly, according to estimates from the U.S. Energy Information Administration.
That gap however, could be filled by imports of just 1 to 2 billion cubic feet per day—well within capacity for existing export pipelines.
The rush to build new export capacity is being driven mainly be expectations that gas use will increase in northern Mexico. Driven by plans from state-owned power generator CFE to switch the bulk of power plants in this region from fuel oil to natgas.
The economic driver for CFE’s switch to gas is certainly real. The utility is running big losses ($474 million in the third quarter of this year alone), mainly due to high fuel-oil costs at its generation facilities.
But constructing or even converting a fleeting of power plants is costly and time-consuming. It’s notable that little of this switching has yet begun. Creating considerable uncertainty over how much demand will actually be there by the time gas starts flowing into export pipelines.
Source : oilprice.com