Why is bigger better in the Permian?

[Douglas Buckland + 6,308]

Mike & D Coyne,

When they run economics on these shale oil operations, do they realistically address the future costs of plugging & abandoning these wells? It seems to me that this will be significant, so will the future liability issue.

This is simply a question as I do not know. This question is not intended to support or disparage the LTO industry...😆

[ceo_energemsier + 1,818]

2 hours ago, Douglas Buckland said:

Mike & D Coyne,

When they run economics on these shale oil operations, do they realistically address the future costs of plugging & abandoning these wells? It seems to me that this will be significant, so will the future liability issue.

This is simply a question as I do not know. This question is not intended to support or disparage the LTO industry...😆

Nitpicking are we now? after being given more facts about shale?

https://www.rrc.state.tx.us/oil-gas/compliance-enforcement/hb2259hb3134-inactive-well-requirements/cost-calculation/

 

 

[Douglas Buckland + 6,308]

2 hours ago, ceo_energemsier said:

Nitpicking are we now? after being given more facts about shale?

https://www.rrc.state.tx.us/oil-gas/compliance-enforcement/hb2259hb3134-inactive-well-requirements/cost-calculation/

 

 

What are the chances of you growing up any time soon? This post was not addressed to you and did not require a response from you.

It is a valid question.

And no, you do not need to reply to this and 'have the last word'.

[Ward Smith + 6,615]

On 5/9/2019 at 8:06 PM, Douglas Buckland said:

Old- Ruffneck,

I think that the 'takeaway' point of the article is that regardless who the operator is, or who's money they are using, it all boils down to reservoir quality, rock properties and fluid dynamics. These are God-given and will not change in the foreseeable future.

The question then becomes, 'If the small to mid cap operators couldn't make a profit and are willing to sell out, why do the big players feel that they can turn it around?'

I am not trying to start a 'pissing contest' between the pro-LTO camp and the guys and gals that think the shale play is built on sand. I am simply asking questions.

This recent post The oil industry cash flow myth brings some important considerations to the forefront. I can see why FCF (free cash flow) is analyzed by investors concerned about dividend paying companies. A professional investor taught me that years ago and we walked through all the darlings of the REIT world then picking winners and losers based off FCF alone. It was eye opening and I picked the best of the bunch at the best price and was very proud of myself for years, until the dang thing tanked. Silly me, I'd neglected to KEEP paying attention to FCF for the one company I'd been so diligent about. Turns out, people leave, things change and a once well run business can get run into the ground quickly by the wrong team. 

But are shale play companies even paying dividends? Diamondback is only paying a paltry half a percent, if you're chasing dividends you're far better off with Exxon. But then again Diamondback has appreciated how much in 5 years compared to Exxon? Maybe cash isn't the king? 

[ceo_energemsier + 1,818]

9 hours ago, Douglas Buckland said:

What are the chances of you growing up any time soon? This post was not addressed to you and did not require a response from you.

It is a valid question.

And no, you do not need to reply to this and 'have the last word'.

Name calling now when you are given facts? You valid question was replied to with a valid answer for the cost that you were looking for from the RRC.

Coming back to the matter or question that was posed about shale... you see the facts about breakevens!!!!!

have a good weekend!!!

[canadas canadas + 136]

There is something still attractive about West Texas crude oil.

[Vince Holley 0]

I answered this question on seeking alpha recently.  The CEO of BP was recently quoted saying that production in shale is the only area of oil production that operates without a brain.  He was saying that every time shale can make a penny, all the little guys start drilling again, pushing the production up and pushing prices back down to below breakeven. The big oil producers are buying up shale so that shale production will now have a brain.  

[ceo_energemsier + 1,818]

1 hour ago, Vince Holley said:

I answered this question on seeking alpha recently.  The CEO of BP was recently quoted saying that production in shale is the only area of oil production that operates without a brain.  He was saying that every time shale can make a penny, all the little guys start drilling again, pushing the production up and pushing prices back down to below breakeven. The big oil producers are buying up shale so that shale production will now have a brain.  

The fly by the night operators who thought they would make a "killing" overnight in shale got "killed off", they overpaid, they under planned or with no plans charged onto armies of shales like Don Quixote , they used service companies who also for the same reason jumped into that boat with many holes. They actually had no clue what they were doing, except they were able to raise some $$$ and go overpay for leases and had no clue what was under their leases.

Eagle Ford has produced over 2,500,000,000bbls of oil ...................................... it may take some sort of brains to produce that much in a short amount of time and it will keep producing more. Just think of the fact that only 10-15% of the oil is recovered in the first go at it!!!! Refrac and other EOR tech will recover much more than that.

Permian is vast multi layered chocolate cream cheesecake!!! with all kinds of textures and flavors. Like a human organ built of many layers of tissues, keep on peeling the layers back using the hitech MRI, CAT scans ultrasounds and nano tech to deliver all the hidden data  find those neural pathways and those inter and intra cellular spaces filled with fluids and how they move about and their properties so on.....

 

 

[ceo_energemsier + 1,818]

2018 was likely the most profitable year for U.S. oil producers since 2013

Net income for 43 U.S. oil producers totaled $28 billion in 2018, a five-year high. Based on net income, 2018 was the most profitable year for these U.S. oil producers since 2013, despite crude oil prices that were lower in 2018 than in 2013 on an annual average basis.

Lower production costs per barrel of oil equivalent (BOE) and increased production levels contributed to a higher return on equity for these companies for the fourth quarter of 2018 than in any quarter from 2013 through 2018.

The companies included in the analysis are listed on U.S. stock exchanges, and as public companies, they must submit financial reports to the U.S. Securities and Exchange Commission. EIA calculates that these companies accounted for about one-third of total U.S. crude oil and natural gas liquids production in the fourth quarter of 2018. However, these companies were not selected as a statistically representative sample but instead because their results are publically available. Their results do not necessarily represent the U.S. oil production industry as a whole.

Source: U.S. Energy Information Administration, based on Evaluate Energy

Most of these companies operate in Lower 48 U.S. onshore basins, with some in the Federal Offshore Gulf of Mexico and Alaska, and some in several other regions across the globe. Because of various corporate mergers and acquisitions in 2018, the number of U.S. producers that EIA examined in this analysis fell from 46 companies in 2017 to 43 companies in 2018.

The aggregated income statements for these 43 companies reveal a trend of relatively low increases in expenses directly related to upstream production in 2018. Although these upstream production expenses per barrel typically correlate with crude oil prices, the magnitude of these increases in 2018 was small compared with the increase in prices.

The annual average West Texas Intermediate (WTI) crude oil price increased 28% from 2017 to average $65 per barrel (b) in 2018, but expenses directly related to upstream production activities increased 16% between 2017 and 2018 to $24/BOE. When including depreciation, impairments, and other costs not directly related to upstream production, expenses for these 43 companies averaged $48/BOE in 2018, the lowest amount from 2013 to 2018.

In contrast to production expenses, between 2017 and 2018, upstream revenue for these 43 companies increased 31% to average $48/BOE in 2018, mainly because of the increases in average energy prices and production. As crude oil prices fell in late 2018, their upstream revenue declined 11% between the third and fourth quarters of 2018.

Source: U.S. Energy Information Administration, based on Evaluate Energy

However, this group of companies reported financially hedging nearly one-third of their fourth-quarter 2018 production at prices in the mid-$50/b range, offsetting revenue declines when WTI prices fell lower than $50/b by the end of the year. Consequently, even with their decline in upstream revenue in the last quarter of 2018, total revenue increased for these 43 companies because of the gains from financial derivatives.

Contributions to revenue from derivative hedges—which increase in value when prices decline—for these 43 companies reached the largest total for any quarter since the fourth quarter of 2014. Financial hedging can act like an insurance policy, reducing risk by stabilizing revenue for producers. When oil prices fall lower than the prices at which producers established a hedge, the producer effectively receives higher revenues than selling at market prices. When oil prices rise higher than the hedged price, hedging results in a loss that is treated as an operating expense.
Source: EIA

[ceo_energemsier + 1,818]

U.S. exploration and production companies (E&Ps) are tapping the brakes on their capital spending in 2019 after two years of strong investment growth and a return to profitability that in 2018 approached the level generated in the $100+/bbl crude oil price environment back in 2014. The pull-back in capex this year appears likely to slow the pace of production growth, and comes despite a 30% rebound in crude oil prices in the first quarter of 2019. What’s going on? Well, many investors remain skeptical about E&Ps, as evidenced by stock prices that remain in the doldrums, and to gain favor with investors, a number of E&Ps are returning cash to them in the form of share buybacks and higher dividends. Today, we consider the current state of investment in the E&P sector, how it’s affected by stock valuations and how it affects production growth.

In a number of blogs over the past three years, we’ve documented the dramatic recovery of the E&P sector from the financial crisis caused by the plunge in oil prices that began in late 2014. Through portfolio high-grading and an intense focus on operational efficiency, the 44 representative E&Ps we track demonstrated that they could grow reserves and increase production on lower capital budgets. The nearly 50% reduction in “finding and development” costs (the cost of “finding” an additional barrel through organic capital spending), excluding acquisitions — from $15.01/boe (barrel of oil equivalent) in 2014 to $8.41/boe in 2018 — helped the E&P sector roar back to profitability last year. Our universe of 44 E&Ps on average netted a healthy pre-tax operating profit of $11.03/boe in 2018, which compares with a barely breakeven profit of $0.07/boe in 2017 and is only 20% below the profit generated by the group in the $100+/bbl environment in 2014. And with first-quarter 2019 oil prices rising 30% — the largest quarterly rise since 2009 — the E&P sector appears to be in a position to report continued profit growth this year.

 

E&P share prices by December 2018 had plunged 40% from their September highs when crude prices slid to $45/bbl, and despite the subsequent oil price rebound, share prices have recovered less than half of their late-2018 declines.

Several oil companies released slimmed-down 2019 capital budgets in late 2018, when oil prices were still sagging. Many industry observers assumed the planned declines in investment reflected conservatism about the oil pricing outlook going forward. The oil price decline turned out to be short-lived, however, with prices recovering strongly starting in late December 2018 and through the first quarter of 2019. Still, updated capex plans released with year-end 2018 results in late January and February continued to mirror the overall trend, and almost no companies moved to revise their budgets upward. (Guidance updates released so far with first-quarter results in late April and early May do not indicate any significant changes from year-end forecasts.)

Figure 1 shows that capital spending for our universe of 44 E&Ps (blue bars, left axis) totaled $135 billion in 2014, but was cut by more than $50 billion in 2015, then slashed in half in 2016 to $40 billion. In 2017, capital outlays rebounded with commodity prices, increasing by about 50% to about $63 billion, and rose by another $15 billion or so in 2018. This $77 billion in 2018 investment generated a 26% increase in pre-tax operating cash flow to $112 billion last year (orange bar to right; left axis) and a 7% increase in production (gray line; right axis). Historically, the higher cash flow would have led to continuing capital investment increases in 2019.  However,  as shown in Figure 1, the companies in our universe announced a collective 12% retrenchment in capital outlays this year. Three-quarters of the 44 E&Ps we track will cut capital spending in 2019, with a median decline of 15%.

Figure 1. E&Ps’ Cash Flow, Capital Spending and Production, 2014-19. Source: Oil & Gas Financial Analytics, LLC (Click to Enlarge)

So, what gives? The E&Ps’ year-end results revealed a major driver of the lower capital budgets: a significant boost in the amount of cash flow being returned to shareholders, primarily through share repurchases. The buyback programs of our group of 44 E&Ps — which are designed to appeal to investors — soared from $4.7 billion in 2017 to $15.6 billion in 2018, while dividends increased 17% to $6.7 billion.

The reduced 2019 capital spending will have an impact on oil and gas output. The surge in investment over the past couple of years drove a substantial 7% increase in production in 2018, including a 13% increase by our Oil-Weighted Peer Group. 2019 guidance indicates oil and gas production growth by our 44 E&Ps will moderate to only 5% this year, or a 200-MMboe rise to 4.7 billion boe. Capital allocation across producing regions in 2019 remains virtually the same as in 2018. The Permian Basin will see the lion’s share of capital investment this year, at 42% of total capital spending. The Eagle Ford Shale is a distant second at 11% of 2019 capex, with the remaining capital investment spread among the Bakken (9%), the Marcellus (8%), International (8%), SCOOP/STACK (6%), the Denver-Julesburg (D-J) Basin (5%), the Utica (2.5%), and the offshore Gulf of Mexico (2%). Next, we review 2019 capital spending and the impact on production by peer group.

Oil-Weighted E&Ps

Figure 2 shows that the 18 E&Ps in the Oil-Weighted Peer Group collectively reduced their 2019 capital budgets by 12%, or $4 billion, to just under $30 billion (blue bar to far right; left axis) despite generating $19 billion in pre-tax operating profit and $45 billion in cash flow in 2018 (orange bar to right; left axis). Capital outlays peaked in 2014 at $47 billion (blue bar to far left), and were slashed by $19 billion in 2015 and by an additional 45% in 2016 to $15.6 billion. In 2017-18, capital spending rebounded along with oil prices, increasing by 60% (to $25 billion) in 2017 and by another 34% (to $34 billion) in 2018. The oil-weighted E&Ps spent $5 billion on share repurchases last year, $3.8 billion more than they did in 2017 and 23% more than in 2014. Dividends paid in 2018 by the oil-focused E&Ps reached $3.6 billion in 2018, 20% higher than in 2017 and on par with 2014 payouts.

 

 

 

Finding and development costs for the oil-weighted E&Ps have fallen from more than $21/boe in 2014 to $12.72/boe in 2018. This allowed the producers to generate 13% production growth in 2018 (gray line, right axis) despite investment that was 30% lower than in 2014. Output growth is expected to slow to 7%, or about 100 MMboe, in 2019. Over 60% of the capital invested by the Oil-Weighted Peer Group this year will be spent in the Permian Basin, in line with the 2018 capital allocation, while 13% will be invested in the Eagle Ford (2% ahead of last year), 9% will be spent in the Bakken and 6% will be spent in the D-J Basin

Oil-Weighted E&Ps' 2018 Profits, Cash Flow, Upstream Spending and Capital Returned to Shareholders

Wednesday, 05/08/2019Published by: jeremy

 

 

 

 

 

Diversified E&Ps

Figure 3 shows that the 16 E&Ps in the Diversified Peer Group are collectively forecasting an 11% decline in capital investment to $29 billion in 2019 (blue bar to far right; left axis) despite generating more than $50 billion in cash flow in 2018 (orange bar to right; left axis). Capital spending for the Diversified E&Ps peaked at $70 billion in 2014 (blue bar to far left), and was slashed by nearly three-quarters by 2016 to $18 billion — the companies were undergoing earth-shattering changes to become profitable in a low oil and gas price environment. These changes included more than 3 billion boe in asset sales in order to reposition themselves by divesting non-core assets. In 2016, capital investment started to rebound, increasing by nearly $9 billion in 2017 and then adding another $6 billion in capital outlays in 2018. A portion of the $21 billion in free cash flow last year was used to increase payout to investors. In 2018, the Diversified E&Ps repurchased nearly $8.4 billion in common shares, nearly three times the amount bought in 2017. Dividend payments last year increased modestly to $2.7 billion, but that was still about 50% lower than what was paid out in 2014 as companies clearly have a preference for opportunistic share repurchases.  

 

Fueling the rise in free cash flow has been a sharp reduction in finding and development costs, which has enabled companies to lighten up their capital commitments while still maintaining reserve and production levels. Finding and development costs have been cut by more than half, from nearly $24/boe in 2014 to $9.24/boe in 2018. While the Diversified Peer Group’s production (gray line, right axis) has been hampered in recent years by the large divestment of assets, the downtrend appears ready to make a turnaround. In 2018, production posted its first increase since 2015, growing nearly 2% in 2018 to 1.8 billion boe, and it is expected to grow another 4.5% in 2019 to nearly 1.9 billion boe.  

About 40% of the Diversified E&Ps’ capital budgets will be invested in the Permian Basin, with 16% allocated outside of the U.S. The Bakken will absorb another 13%, compared with 9% last year. The SCOOP/STACK and Eagle Ford are each taking on 10% of peer group capex, similar to last year’s capital allocation.

 

Gas-Weighted E&Ps

Capital investment for the 10 E&Ps in the Gas-Weighted Peer Group has followed a slightly different trend than the rest of our E&P universe. Capital spending by these gas-focused companies peaked in 2014 at just over $17 billion (blue bar to far left in Figure 4; left axis) and subsequently fell by more than 60% to its 2016 bottom of $6.7 billion. Capex rebounded in 2017 by nearly 90% to $11 billion, but stagnated in 2018 before an expected 16% decline this year.  

The gas-weighted E&Ps have also reduced capital costs, but not to the same extent as the other peer groups. Finding and development costs fell by only about 20% between the $4.52/boe posted in 2014 and the $3.75/boe reported in 2018. Nevertheless, free cash flow has increased sharply over the past few years, as have share repurchases, which are up seven-fold to $2.2 billion in 2018 — multiples of what was repurchased in the 2014-17 period. Dividends in 2018 amounted to $306 million, nearly 20% higher than in 2017, but still well below the 2014 payouts. As shown in Figure 4, production for the Gas-Weighted Peer Group has risen steadily, from 819 MMboe in 2014 to 1.261 billion boe in 2018, a compounded annual growth rate of 9.5%. The rate of change is expected to slow precipitously in 2019, to only 1.8%, resulting in 2019 production of 1.284 billion boe.

Figure 4. Gas-Weighted E&Ps’ Cash Flow, Capital Spending and Production 2014-19. Source: Oil & Gas Financial Analytics, LLC (Click to Enlarge)

Three-quarters of the gas-weighted E&Ps’ 2019 investment will target Appalachia (60% Marcellus, 15% Utica), which is on par with 2018. An additional 7% is being invested in the Eagle Ford and another 4% being deployed in SCOOP/STACK.

While crude oil prices got off to a slow start in 2019, the ensuing rally looks like it will push E&Ps’ first-quarter 2019 profits to exceed fourth-quarter 2018 results and set the stage for a strong 2019 as a whole.  We will continue to monitor E&P announcements and will provide an update at mid-year to highlight any changes in capital spending, production and capital allocation trends we spot.