Post Tagged with: "Marcellus Shale"

Cabot Oil & Gas Expands Share Repurchase Program

Cabot Oil & Gas Expands Share Repurchase Program

Cabot Oil & Gas (NYSE: COG) announced Q2 results, showing net income of $42.4 million, or $0.09 per share.

Highlights

  • Daily equivalent production of 1,895 MMcfe/d
  • Adjusted net income of $57.9 million
  • Net cash provided by operating activities of $273.9 million
  • Discretionary cash flow of $196.5 million
  • Returned $239.6 million of capital to shareholders through dividends and share repurchases
  • Improved operating expenses per unit by eight percent YOY

Current operations and outlook

Cabot is currently operating three rigs and two completion crews in the Marcellus Shale and plans to place 37.0 net wells on production in conjunction with the anticipated in-service of the Atlantic Sunrise pipeline project during the second-half of August 2018.

Cabot in Q2 closed on the sale of its oil and gas properties in the Haynesville Shale for net proceeds of $29.2 million, which included a $5.0 million deposit that was received in the fourth-quarter of 2017 making Cabot a pure play E&P focused on the Marcellus.

Cabot Oil & Gas Expands Share Repurchase Program

Cabot Oil & Gas Assets; Source: Cabot Oil & Gas

The company has also updated its 2018 daily production growth guidance range from 10 – 15 percent to 10 – 12 percent and increased its full-year capital budget by $10 million to $960 million to reflect additional spending associated with its equity ownership in the Atlantic Sunrise pipeline project.

Share repurchase program expanded

Cabot repurchased 11.6 million shares at a weighted-average share price of $23.54, including 1.6 million shares that were previously reported in the first-quarter 2018 earnings release. Over the past year the company has repurchased 20.0 million shares at a weighted-average share price of $24.09 and since reactivating the share repurchase program in Q2 2017, Cabot has reduced its shares outstanding by over five percent to 441.2 million shares.

Cabot Oil & Gas Expands Share Repurchase Program

Additionally, the board of directors has authorized an increase of 20.0 million shares to the share repurchase program, bringing the current remaining authorization to 30.1 million shares. Based on the closing share price on July 26, 2018, the program implies approximately $745 million of additional share repurchases.

Q & A

Selected Q & A from Cabot Oil & Gas’ Q2 earnings call included below:

Q: Dan, in your prepared remarks, you’d talked about the Upper Marcellus tests that you’ve drilled in the past. I know it’s not been the focus of yours right now. Can you just talk about what assumptions you’ve made in that? You guys have laid out before like a 20-year production forecast. What assumptions are made in that forecast for the Upper Marcellus?

Chairman, President, and CEO of Cabot Oil & Gas, Dan O. Dinges: The 20-year forecast that you’re talking about, we’ve assumed the – where we are today and what we’ve seen, Drew, with the 30 completions that have been completed in our old technique. We’ve assumed the 2.9 Bcf in that forecast.

Q: Okay. And I guess just looking at share repurchases, obviously, you guys came out and increased the program here. But I guess if I just sort of look at that high level, we have kind of seen some weakness in NYMEX gas prices. I know you guys also had this debt repayment that you had to recently make here over the last couple of weeks. Irrespective of that stuff, I mean, do you guys still plan on being pretty aggressive here in H2 with the buyback program?

Chairman, President, and CEO of Cabot Oil & Gas, Dan O. Dinges: Yeah, Leo, the conversation again at our board meeting this week was specifically along the lines that I have mentioned in the past. And that was that our authorization is not optics, it is for action. And that is our intent to execute on the authorization that the board has granted. So, the takeaway would be that we fully intend to continue our program that we’ve implemented.

Q: I know in the past you said all of the Atlantic Sunrise, when it comes online, are going to be taking volumes that go from – that are in the local market on to Atlantic Summers. But is it possible that you’re not actually going be delivering your Bcf a day on within a couple of weeks of startup, that you’re going to ramp to that?

Chairman, President, and CEO of Cabot Oil & Gas, Dan O. Dinges: On Atlantic Sunrise?

Q: Right.

Chairman, President, and CEO of Cabot Oil & Gas, Dan O. Dinges: Charles, we’re planning on utilizing the capacity available in Atlantic Sunrise as soon as it is available. The connection to our gathering system of the upstream portion of Atlantic Sunrise is designed to take the volume of gas that we committed to, and it is our full intent to deliver the gas as soon as Atlantic Sunrise will take it.

One of the things on our conservatism, I wasn’t trying to be cute on the comment on conservatism, Charles, but one of the things that, I think, is relevant, the ramp-up and shifting in a small area, a Bcf of gas and coordinating two power units that are coming on at the same time and moving gas around in a small geographic area is done with the switch of the valves, I guess, but it’s multiple valves, it’s multiple coordination, to get it done and get it all smoothed out.

So in light of the time of year, which the shoulder month time of the year, when you get a little bit of the early cooler weather, it ramps up the pressure in the pipes, the pipes that are within the basin and the amount and volumes that the pipelines will accept at the higher pressure starts creating some reduction in the volumes that you’re going to be able to put into the pipe. That has happened every year back-to-back, back-to-back without exception.

Q: Okay. And then, I guess, the other side is just kind of following up a little bit on the exploratory programs, but in the context of the dividend – I’m sorry, the buyback. You talked about one thing that has been a kind of gating item for the buyback has been getting the infrastructure up and running and commissioned, as expected. Just wondering to what extent has – or have the exploration programs also been kind of governors on committing even more in a way of buybacks? And to the extent you did see or you did move on, let’s say, from the second program, would it be fair then to assume you’d see another big step-up in buybacks, or any commentary along those lines?

Chairman, President, and CEO of Cabot Oil & Gas, Dan O. Dinges: Well, the exploratory portion of our available cash has not influenced our decisions on the level of buybacks. We anticipate our buyback program to be, as we’ve laid out, opportunistic. And it dovetails now – along with the comment I made on dividends, it dovetails now with our anticipation of both in-basin power demand and our commissioning of Atlantic Sunrise. So, the amount of money compared to Cabot’s available capital and cash that’s being allocated to the exploratory effort is de minimis. And it does not impact our decision on buybacks.

The Oil and Gas Conference®

Cabot Oil & Gas is presenting at EnerCom’s The Oil & Gas Conference® at the Denver Downtown Westin Hotel, Denver, Colo. Aug. 19-22, 2018. EnerCom expects to have more than 80 presenting oil and gas companies and more than 2000 financial professionals attending this year’s conference.

To learn more about the conference and presenter schedule please visit the conference website here.

EQT Corporation Streamlines Midstream Through Q2

EQT Corporation Streamlines Midstream Through Q2

EQT Corporation (NYSE: EQT) announced its Q2 earnings, which was highlighted by a massive jump in both net cash provided by operating activities and in adjusted operating cash flow. EQT also recapped major sales of assets made in Q2, along with plans for further stock buyback initiatives.

Highlights:

  • Increase of 116% in net cash provided by operating activities
  • Increase of 128% in adjusted operating cash flow
  • Decrease of 20% in Production’s per unit cash operating costs
  • Approved a 19.9% retention of SpinCo stock
  • Announced plan to separate midstream business
  • Authorized a $500 million stock buyback program
  • Completed midstream streamlining transactions
  • Completed the sale of Huron and Permian assets

Net income attributable to EQT Q2 2018 decreased due to higher operating costs, including impairments of long-lived assets and leases, transaction-related expenses, higher interest expense, and losses on derivatives not designated as hedges despite higher revenue that resulted from an 83% sales volume increase, lower corporate income taxes, and higher pipeline, water, and net marketing services revenue.

Adjusted net income increased $104.9 million in Q2 and adjusted operating cash flow including transaction-related expenses and excludes the non-controlling interests in EQT Midstream Partners, LP (EQM) and Rice Midstream Partners LP (RMP), increased 128%.

EQT is retaining 19.9% of its shares in the midstream company SpinCo that will be spun-off to EQT Shareholders.

The EQT board has approved $500 million stock buyback program following the repurchase of 700,000 shares of EQT common stock at an average price of $55.25 earlier on in Q2 2018.

EQT to separate from Midstream business

EQT Corporation Streamlines Midstream Through Q2

Source: EQT

EQT Corporation Streamlines Midstream Through Q2

Source: EQT

Streamlined Midstream

The Company completed its previously announced plan to streamline its midstream structure, including:

  • On July 23, 2018, EQM acquired Rice Midstream Partners LP (RMP) in a unit-for-unit merger at an exchange ratio of 0.3319x. EQM also repaid $260 million of RMP debt bringing expected 2018 production to 1.54Tcfe
    • EQT finished its acquisition of Rice Energy in Q4, finalizing the combination in November. The company estimates SG&A savings of about $110 million in 2018, and CapEx savings of $210 million.
  • On June 25, 2018, EQM completed its offering of $2.5 billion in aggregate principal of three tranches of senior notes.
  • On May 22, 2018, EQT sold all of its RMP incentive distribution rights to EQT GP Holdings, LP (EQGP) for 36.3 million EQGP common units.
  • On May 22, 2018, EQM acquired EQT’s retained midstream assets for $1.15 billion in cash and 5.9 million EQM common units (May 2018 Acquisition).
  • On May 1, 2018, EQM acquired Gulfport Energy Corporation’s 25% ownership interest in the Strike Force Gathering System for $175 million in cash.

Huron and Permian Sold

During Q2 EQT completed the sale of its Huron assets located in Southern Appalachia to Diversified Gas and Oil PLC, for $575 million cash. The transaction relieved EQT of approximately $200 million of plugging and other liabilities associated with the assets. EQT retained the deep drilling rights across the acreage.

EQT also completed the sale of its Permian Basin assets located in Texas for $64 million cash, which also relieved EQT of approximately $40 million of related plugging and other liabilities.

Q & A

Selected Q&A from EQT’s Q2 earnings call:

Q: You talked a lot about the buyback here, and it seems like there are three avenues you have to fund the buyback; asset sales, which you’ve done with the Huron sale here; the midstream SpinCo proceeds, which you’re highlighting might be an option to use for share repurchase; and the third lever might be activity levels and growth. Can you talk about the key constraints that you’re looking for, particularly on the latter two, i.e., what your target balance sheet would be as you think about how much proceeds could be used from the midstream SpinCo towards share repurchase, and then also whether you would consider slowing your growth rate and using the excess free cash flow for share repurchase?

EQT SVP & CFO, Robert J. McNally: Yeah. So, there’s several things in that question, Brian. So, let me start and deal with them one at a time. Yeah, as we think about the appropriate growth rate for the company, we certainly see the need to balance generating free cash with a moderate growth rate. We’re currently working through that with the board and we’ll have a better guidance for you later in the year on what we think the forward growth rate will be. But we certainly do think there has to be a balance between returning cash to shareholders with growth.

In terms of the share repurchase, we have a $500 million authorization from our board, and once we have used that up, depending on what the balance sheet looks like and what the environment is like, we can certainly consider going back to the board for further authorization. In previous calls and commentary, we have said that we want to see our leverage levels at less than 2 times debt to EBITDA and preferably more like 1.5 times debt to EBITDA. And so, that’s the target range that we still believe is right for EQT going forward.

Q: Given the deficit we have in storage and some improvement that we’ve seen in local Appalachia prices, combined with some of the efficiency gains you’ve highlighted, how do you think about potentially increasing activity or what would you need to see to increase activity?

EQT SVP & CFO, Robert J. McNally: Yeah. I think clearly, Brian, in a higher gas price environment, higher realizations, the math on returns will tell us that if we’re better off to increase growth rates and production. But we haven’t seen a significant move in realized prices. While there have been some modest improvements locally in bases, that’s been partially offset by lower NYMEX pricing. So, I would say that that dynamic isn’t pushing us to increase production at this point.

Q: On retaining those SpinCo shares, can you give us some sense of what is your plan to like – how do you look to monetize that? Is it something we should expect pretty quickly? Is it going be systematic, opportunistic? And with that, what was really the driving force behind making that decision to retain that, those SpinCo shares? Was it specifically to have the access to extra liquidity or was it for more, during the spin process, to make it a little, I guess, cleaner for investors that would have been spun a little bit more shares?

EQT SVP & CFO, Robert J. McNally: Yeah. The real job right here was this was an avenue for us to right-size the EQT balance sheet and get to the liquidity levels that we want and be able to fund a share buyback prior to the spin, because we were retaining that value and it gives us confidence that we would have the available capital to fund the buyback without putting undue leverage at the SpinCo level, all right. So, we want – our goal all along was that we would have two independent companies with strong healthy balance sheets, and this was the most elegant way to accomplish that goal, as well as fund the share buyback.

Q: I was wondering if you could kind of walk us through the steps in terms of the separation. You mentioned that the Form 10 would be filed in mid-August. But walk us through kind of the timing and what kind of happens from here. And at what time would you be prepared to provide kind of standalone kind of guidance for EQT Production?

EQT SVP & CFO, Robert J. McNally: Yeah. So, from here – we’ve essentially completed all of the clean-up transactions that we announced in April and the related financing transactions. So, I would like to say that I’m extremely happy with the progress that we’ve made and the hard work that our teams have done. I’m really impressed with what we’ve gotten done. So, what’s left now is to file the Form 10, which we expect to do by mid-August, and then with that starts the process with the SEC, which – that timing then is a bit out of our control.

It depends on how many rounds of questions the SEC has, and then we’re also waiting on the PLR from the IRS. And we think that that likely pushes us into the fourth quarter now between those two gating items. I suspect that as we get closer to – as we get closer to separation, we will likely want to get out and meet with investors, and at that point, I think you’ll get standalone guidance from both EQT and SpinCo. So, I don’t know what the dates of that will be. But I think in the month leading up to the spin being finalized, you would expect to hear from us with more concrete guidance for both SpinCo and EQT.

Q: Is there some thought in your mind to target that leverage – previous leverage target you had mentioned 1.5 times or to push that lower? And how are you thinking about using the proceeds between share buybacks or return of cash to shareholders and debt reduction?

EQT SVP & CFO, Robert J. McNally: Well, I think that the – the $500 million share repurchase that we have authorized, that’s all that we have authorized at this point, and the majority of the rest of the value will likely go for debt reduction. And we do think that getting down to that 1.5 times debt to EBITDA is the right place for EQT to be. It puts us in a strong liquidity position. We don’t feel the need to get – to move it a lot lower than that. But if we’re a little lower, that’s fine too.

Range Resources Releases 2018 CapEx, Proved Reserves Update

Range Resources Releases 2018 CapEx, Proved Reserves Update

Approximately 80% of 2018 capital is projected to be spent in the Marcellus, generating greater than 25% growth

Range Resources Corporation (ticker: RRC) announced a 2018 capital budget of $941 million, which is below anticipated 2018 cash flow at current strip prices and generates annual production growth of approximately 11%.

Additionally, Range announced a five-year outlook from 2018 through 2022 that generates cumulative free cash flow of approximately $1 billion and reduces leverage to below 2x net debt to EBITDAX by year-end 2022, assuming no asset sales.

Range Resources Releases 2018 CapEx, Proved Reserves Update

Range Resources Overview, Jan. 2018

Capital spending

Cash flow generated from asset sales or an increase in commodity prices would be expected to be used to pay down debt in 2018, Range said in a press release.  Approximately 80% of 2018 capital is projected to be spent in the Marcellus, generating greater than 25% growth from Range’s southwest Marcellus assets and full utilization of transportation capacity out of Appalachia by the end of the year.

To support the 2018 capital program, the company has also increased its hedge position, with approximately 70% of expected 2018 natural gas production currently hedged at an average price of $3.09.

Range Resources Releases 2018 CapEx, Proved Reserves Update

Range Resources Marcellus Inventory Map, Jan. 2018

Capital spending for 2017 was approximately $1.27 billion, approximately 10% above the planned $1.15 billion budget.  In North Louisiana, the increase was primarily driven by higher capital spending in the expansion area, higher than expected costs on wells completed in the second half of 2017 and on wells drilled but not completed in 2017, Range said.

The increase was also driven by higher spending in the Marcellus, where well results have been strong and new transportation capacity agreements are on-line or expected to be on-line in early 2018

Five-year outlook

Range’s current five-year outlook would deliver an annual production CAGR of approximately 13% on a debt-adjusted per share basis while generating approximately $1 billion of cumulative free cash flow, at strip pricing.

Any proceeds from assets sales are expected to be used for debt reduction.  According to the company, margin improvement is expected due to improved access to better markets and a continued improvement in the company’s cost structure through utilization of existing infrastructure and lower interest expense.

The five-year outlook assumes all production growth is from Range’s Marcellus inventory, while North Louisiana production is held roughly flat from year-end 2018 through the remainder of the plan.  At the end of the five-year outlook, Range would still have over 3,200 locations in the core of the Marcellus alone.

Range Resources CEO Jeff Ventura said, “We have entered a new era of shale development where companies that captured the most prolific resources have the ability to generate better returns for shareholders.

“For Range, the flagship asset and growth driver of the company will continue to be our large, high-quality, de-risked inventory in southwest Pennsylvania.  As demonstrated in our five-year outlook, the quality of our assets allows Range to improve corporate returns and our leverage profile in the near-term, while generating competitive growth of production and reserves on a debt-adjusted per share basis.

“Looking beyond the five-year outlook, as the industry exhausts its core inventory, we believe Range will be well-positioned with a long runway of high-quality drilling locations from which we can drive long-term value.”

Proved reserves update

Commenting on Range’s 2017 proved reserves, Ventura said, “Range had another solid year of reserve growth, with impressive drill-bit finding costs of only $0.31 per Mcfe.  Performance revisions are included, but revisions from increased prices are excluded.  Positive performance revisions continued in 2017 as we extended laterals, improved targeting and drove efficiencies throughout our developed leasehold and infrastructure.

“Future development costs for proven undeveloped locations are estimated to be $0.38 per Mcfe, which should improve our top-tier unhedged recycle ratio to over 3x.  Range added a record 3.5 Tcfe to proved reserves from extensions, discoveries and additions, driven primarily by our large inventory of low-risk, high-return projects in the Marcellus Shale.

“Looking forward, we see capital efficiency gains continuing as we drive down normalized well costs with longer laterals and drilling on existing pads, while enhancing recoveries with improved targeting and completions.  Similar to previous years, this strong reserve growth reflects high quality acreage, as less than one-third of our offset proven undeveloped locations are currently recorded for each horizontal producing well.

“We believe this will provide consistent SEC reserve growth over time as additional acreage is classified as proven and capital is allocated to offset locations.  Our economic resilience is further demonstrated in the year-end PV10 reserve value of $9.5 billion using futures strip pricing from year-end and current sales contracts.  With 55% of SEC reserves being proved developed (PD), our PD reserve life and debt per PD reserve ratios remain exceptionally strong,” Ventura said.

SUMMARY OF CHANGES IN PROVED RESERVES
(in Bcfe)
 
Balance at December 31, 2016  12,072
 
  Extensions, discoveries and additions   3,488
  Purchases    10
  Performance revisions:
  PUD improved recovery   597
  Field performance 531
  Total performance revisions    1,128
  Reclassification of PUD to unproved under SEC 5-year rule (668 )
  Price revisions  46
  Sales of proved reserves  (81 )
  Estimated production  (733 )
Balance at December 31, 2017  15,262

During 2017, Range added 3.5 Tcfe of proved reserves through the drill-bit, driven by 3.2 Tcfe from the company’s Marcellus development.  The extensions, discoveries and additions amount excludes 597 Bcfe of Marcellus reserves associated with undrilled locations that now have increased recovery estimates as a result of longer laterals, better lateral targeting and increased frac stages, the company said.

This improved recovery estimate is included in the revision category.  The average lateral length for existing proved undeveloped locations increased to approximately 9,000 feet in the 2017 report from 7,162 feet in the 2016 report, while newly added proved undeveloped locations in the Marcellus incorporate an average lateral length of approximately 9,500 feet.

Field level performance increased reserves by 531 Bcfe due primarily to the continued improvement in the well performance of existing Marcellus producing wells.  As a result of Range’s success in drilling longer laterals, the future development plan has been re-optimized resulting in some previously planned wells not being drilled within five years from their original booking date, the company said.

To reflect this, Range removed 668 Bcfe of proved undeveloped reserves that now fall outside the SEC mandated five-year development window.  The company expects these proved undeveloped reserves to be added back in future years as field development continues.

According to Range Resources, the wells that remain have longer laterals, greater estimated ultimate recoveries (EURs) and lower per foot drilling and completion costs resulting in improved economics.  The resulting corporate proved undeveloped development cost of $0.38 per Mcfe is a conservative estimate, based on 2017 well costs, EURs and lateral lengths, assuming no future efficiencies, Range Resources said.  The higher SEC price for 2017 as compared to 2016 resulted in an upward pricing revision in proved reserve volumes of 46 Bcfe.

Year-end 2017 proved reserves by volume were 67% natural gas, 30% natural gas liquids and 3% crude oil and condensate.  Proved developed reserves represent 55% of the company’s reserves.  The company’s Appalachia reserves were audited by Wright & Company, Inc. and North Louisiana reserves were audited by Netherland, Sewell & Associates, Inc.  The audited reserve value estimates for each area were within 3% of aggregate estimates prepared by Range’s petroleum engineering staff.

Summary of Changes in Proved Reserves by Category for 2017
 Proved
Developed
Reserves
Proved
Undeveloped
Reserves
Total Proved
Reserves
(Bcfe) (Bcfe) (Bcfe)
Proved Reserves 12/31/16 6,770 5,302 12,072
Extensions, discoveries and additions 314 3,174 3,488
Purchases 5 5 10
PUDs drilled 1,862 (1,862 )
Performance revisions 156 972 1,128
5-year rule PUDs reclassified (668 ) (668 )
Pricing revisions 46 46
Sales of reserves (72 ) (9 ) (81 )
Estimated production (733 ) (733 )
Proved Reserves 12/31/17 8,348 6,914 15,262
 

Percent by Category

55 % 45 % 100 %
Increase in Reserves by Category 23 % 30 % ` 26 %

Q4 production

Company production in fourth quarter 2017 is expected to be 2.17 Bcfe per day, level with previous guidance, Range Resources said in a recent press release.  Marcellus production is expected to be 1.80 Bcfe per day, approximately 27% higher than a year ago, driven by results in the Marcellus, particularly in the company’s super-rich area.

North Louisiana volume is expected to be 350 Mmcfe per day for fourth quarter 2017.  The North Louisiana division saw productivity improvements in the fourth quarter well results compared to the first half of 2017 as a result of larger, higher cost completions.

Core drilling inventory

Range has an extensive stacked-pay acreage position in both Appalachia and North Louisiana and the company also has a network of over 200 existing well pads.  According to the company, these pads are designed to accommodate an average of 20 wells from any combination of the Marcellus, Utica or Upper Devonian horizons.

Range Resources Releases 2018 CapEx, Proved Reserves Update

Range Resources Appalachia Assets, Jan. 2018

Range Resources said that most pads currently contain only 4-6 producing wells, giving the company the opportunity to drill thousands of future wells utilizing existing roads, pads and infrastructure.

The table below reflects Range’s estimate of the remaining core drilling inventory for the Marcellus and Lower Cotton Valley.  The total inventory count is based on thousands of historical producing wells and a vast collection of geological information that support the company’s estimates.

Estimated Future Core Drilling Locations – December 31, 2017
(Excludes Deep Utica and Upper Devonian Locations)

 
Area
 

Net Acres

Average Lateral
Length
Undrilled
Locations
Marcellus- SW- Liquids areas 335,000 10,000 ft. 2,700
Marcellus- SW-Dry area 170,000 10,000 ft. 800
Marcellus- NE 90,000 10,000 ft. 300
Lower Cotton Valley 205,000 7,500 ft. 600
  Total 800,000   4,400

 

Thick Hedge Book and New Pipelines Power Antero Resources into 2016

Thick Hedge Book and New Pipelines Power Antero Resources into 2016

Hedge book’s mark-to-market value listed at $3.1 billion

Attractive hedges have the ability to make a significant impact on company balance sheets, and its positive effects (along with access to favorably priced markets) are apparent in a January 13 business update from Antero Resources (ticker: AR).

The Appalachia-focused producer reported a realized natural gas price (after settled commodity derivatives) of $4.40/Mcf in Q4’15 – a staggering $2.13 positive differential to Nymex spot prices. The favorable prices come at the perfect time, as Antero boosted its overall dry gas production by 18% compared to the prior quarter and virtually the same amount as Q4’14. Management attributed the increase to the commissioning of the Stonewall gathering pipeline in December, opening up lanes for AR to sell “virtually all of its gas to favorably priced markets.” The Stonewall created a negative differential to Nymex of just ($0.14), compared to December differentials in the range of ($0.80) compared to data compiled from EnerCom’s Monthly Report.

AR-hedgesThe hedge position “enables the projected 20%+ growth in 2016 despite the otherwise dismal pricing,” said a note from Capital One Securities.

If It Ain’t Broke, Don’t Fix It

In association with the announcement, Antero revealed an increase in its hedge position to 3.5 Tcfe through 2022 at an average fixed price of $3.79/Mcfe. The mark-to-market value is listed at $3.1 billion and is believed to be the largest gas hedge position in all of U.S. E&P. That doesn’t include $1.7 billion of realized gains since 2009.

AR hedged 94% of its 2015 production guidance at $4.43/Mcfe, and is only increasing the book in the near term. In a January 2016 company presentation, Antero says 100% of its 2016 volumes are hedged at $3.94/Mcfe. Exact details on 2017 figures have not yet been released since AR has yet to release volume figures, but 2,073 Mcfe/d (roughly 58% higher than 2015 volumes) are locked in at $3.57/Mcfe. With the help of the Stonewall and Mariner East 2 gathering pipelines, AR believes 95% of its sales volumes have the inside track to favorable markets.

As seen in the well economics slide below, three of the nine Marcellus/Utica regions realize more than triple the price due to hedge benefits. AR is keying in on those area and was the most active regional producer, in terms of rig count, in H2’15.

AR-wells

Can Improvements be Made?

A note from Seaport Global Securities points out that the premium from more favorable markets “is largely offset by increasing FT costs (~$0.35/Mcfe in 2015 goes to $0.46/Mcfe in 2016) and increasing FT commitments (AR expects ~1.5 Bcfpd of excess capacity in 2016).”

In a study of seven Marcellus/Utica producers, analysis from EnerCom and Oil & Gas 360® revealed that Antero’s cash and F&D costs per Mcfe were the highest of the group. Its rapid growth stage carries some of the blame for the costs, but the growth stage is now leveling off and efficiencies are coming to the forefront. Its expenditures for 2015 are nearly half of the amount from 2014, and volumes have not suffered from the difference in activity.

Source: WPX

Energy Market Upside: EQT Corp. Welcomes 2016 with $1 Billion CapEx Plan—Self-Funded

The oil and gas market is approaching the end of 2015—which will no doubt go down as a highly tumultuous year for the industry. In spite of the dive in oil prices, some companies have positioned themselves well for capturing the upside through advantageous acquisitions, reliable takeaway capacity, attractive hedges and low-cost production. Or a combination of factors.

Today’s focus is EQT Corporation, a Marcellus/Utica pure play headquartered in Pittsburgh, Pennsylvania. The company has drilling rights to nearly 3.4 million acres across Kentucky, Ohio, Pennsylvania, Virginia and West Virginia, and is established as one of the low-cost providers in the natural-gas rich Appalachia.

Below are some of the strengths of EQT Corporation:

  • Three-year finding and development costs of $0.73/Mcf, ranking as the fourth cheapest natural gas producer in EnerCom’s E&P Weekly Benchmarking Report of 89 companies.
  • Asset intensity (described as the percentage of every EBITDA dollar required to maintain a flat production profile) of only 35%, ranking the fourth lowest in the Benchmarking Report.
  • A 2016 capital expenditure program that will be funded by cash on hand, cash from operations and proceeds from midstream asset sales to its midstream subsidiary.
  • A 2016 drilling program focused on its core West Virginia/Pennsylvania wells, which KLR Group believes can provide 45% to 50% rates of return.
  • Production guidance in line to provide 17.5% year-over-year growth despite a 40% cut in exploration and production costs.
  • Approximately 33% of projected 2016 volumes hedged at $3.88/Mcf, well above the average realized price of $2.12/Mcf in Q3’15.

Some may question EQT’s decision to drill cost intensive deep Utica wells in 2016, but Steven Schlotterbeck, President of Exploration and Production, assured investors of the returns in the company’s Q3’15 conference call. “Using the lowest EUR of our range and assuming the high end of our cost per well target of between $12.5 million and $14 million per well we estimate returns at a $2 wellhead gas price to be north of 20% for a 5,400 foot lateral well,” he said. EQT plans on drilling at least five deep Utica wells in the upcoming year, with the possibility of doubling that amount.

EQT appears to be getting a running start heading into 2016, as the company will work off the inventory from the tail end of its 2015 program. Schlotterbeck explains: “The backlog in terms of frac stages complete but not online grew a bit this quarter. Our expectation is that the fourth quarter will be a pretty big quarter for new TILs. Most of those will be in the back half of the quarter, so it won’t affect volumes in the quarter very much but should be coming on late.”

Source: WPX

West Virginia’s Coal Industry is Reeling – Will Shale Gas Take Its Place?

Seal_of_West_Virginia.svgAn Exclusive Interview with Keith Burdette, Secretary of Commerce for West Virginia

Coal has powered West Virginia’s economy for centuries. Generations of West Virginians have come and gone in the Mountain State, and its stalwart blue-collar coal industry continuously attracts the next wave of young people in search of a career in the rolling hills of Appalachia.

But the latest generation of West Virginia coal miners—and the ones coming up behind them—are faced with unprecedented uncertainty: do we have a future?

The Environmental Protection Agency’s severe regulatory enforcements on coal-fired power plants, combined with the evolution of natural gas as a less carbon intensive fuel generator—sometimes referred to as a “bridge fuel” by environmental policy makers—are threatening the viability of the Appalachia’s most relied-upon resource.

Secretary-Burdette

Keith Burdette, Secretary of Commerce West Virginia

Keith Burdette, Secretary of Commerce for West Virginia, has watched the state’s economy develop throughout his lifetime. Burdette was elected to the West Virginia State Senate at only 27 years of age and named the President of the State Senate seven years later in 1989.  Throughout the next two decades, he held various legislative positions while starting and managing his own consulting firm.

Burdette is currently West Virginia’s Secretary of Commerce, a role he assumed in 2010 after the election of Governor Earl Ray Tomblin.

Secretary Burdette spoke to OAG360® from his office in Charleston, West Virginia, in this exclusive interview.

WEST VIRGINIA’S COAL INDUSTRY

OAG360: Would it be fair to say that your state is being attacked, considering the effects that the Clean Power Plan will have on West Virginia’s work force and overall economy?

BURDETTE: I don’t get into the war on coal. I leave that to the other political leaders in the state.

However, there are a multitude of issues that are creating challenges for coal. Federal regulations, no question about it, are placing a burden on the coal industry. The cheap pricing and abundance of natural gas is placing a burden on the coal industry. Remember, seven years ago we were trying to figure how to import natural gas. Now we’ve got it coming out of our ears. In West Virginia, there are other dynamics. In the southern coal fields, the difficult topography makes it more expensive to mine. We end up competing against pit mining in the Midwest, which is actually cheaper to do.

West Virginia, Kentucky and Virginia Provided the Fuel that Powered the U.S.A.’s Growth

I don’t throw the blame at any one issue, but I think the Administration does need to consider that their changes in policy are creating a huge economic challenge in the coal fields, especially in Appalachia. It doesn’t matter if you’re from eastern Kentucky, Virginia or from southern West Virginia. These are all very topographically challenged areas that have provided coal to this country since before the Industrial Revolution, and has quite literally provided the fuel for this country’s growth.

Those southern coal fields have largely produced a one-item economy… What exactly do you do with 100,000 people? These people have been in the coal business for multiple generations and have earned a great deal of money. Now we’re trying to convince coal miners to retrain for other careers, because we’re not going to need as many of those workers in the future, regardless of what happens with the EPA plan.

Coal Provided Six-Figure Incomes Straight out of High School, but those Livelihoods are Drifting Away

If you live in southern West Virginia and were willing to go underground and mine for coal, you could have earned six figures straight out of high school if you were willing to work overtime. So now we we’re trying to convince them to go back to school, incur some debt, and then make half as much money as they used to. So it’s not just an economic challenge, it’s a cultural challenge too.

Now, I do happen to believe that challenges present an opportunity to create diversity in the coal regions. But it’s not going to be easy for many of us. It’s going to require a lot of investment to get the infrastructure in place because everything is currently suited for the coal industry. I don’t want to sound too needy here, but I think the government kind of owes it to us. And I’m not meaning just West Virginia, I mean the whole region. The [government] policy is changing the livelihoods of many, many people. And they need to recognize the fact that their changes are expected to come along pretty quickly, and they need to give hope to those people who are watching their livelihoods drift away from them.

We’re Just Training People to Leave

I encourage the Federal Government to look at this situation with compassion and recognize this is not simply a situation of training people. Right now, we’re just training people to leave, because currently, the jobs are not in the coal fields. We’re doing way more than training people, we’re repositioning entire communities.

OAG360: Would you say you feel blindsided by these regulations?

BURDETTE: Well that’s a great question, and I’m not sure that I have a great answer for you. I don’t feel blindsided, but I think the magnitude and the speed of the reaction has been surprising to us.

State’s Revenue Drop is Dramatic and Massive

I’ll give you an example as far as the state budget is concerned. This fiscal year in West Virginia started on July 1, and it was expected to be a break-even year. Sixty days into the year at the end of August, we were missing our revenue estimates by about $12 million – not terrible, certainly manageable. But then by the end of September, we were $60 million down. At the end of October, we were $90 million down. So, the speed by which it has affected the state’s revenue caught everybody off guard. I don’t think anybody expected it to be that dramatic and massive.

Did we see the cost from the battle with coal? Yes. Did we understand that the policies in Washington, DC, were going to make coal sales more challenging? Yes we did. But, that doesn’t make it any easier to turn the ship around. If you prefer to take a glass half-full approach, I think everybody understands that there’s going to have to be some pretty dramatic changes. All of these families are like anybody else – mouths to feed, mortgages to pay, car payments to make.

Just Relocate and Find other Jobs

Consider this equation also: some people say, “Well, you just need to relocate and find other jobs.” But it’s very hard to relocate when you have basically your entire life’s savings tied up in your house and you can’t sell it because everybody is leaving town. Who would buy it now? So there are a lot of challenging problems that won’t be solved with what I call the ‘bumper sticker mentality’. It will require some very fundamental shifts in the coal fields. We have to give these families some hope.

WEST VIRGINIA’S NATURAL GAS INDUSTRY

OAG360: Broadly speaking, can you talk about some of the trends and differences you have noticed in West Virginia as the Marcellus and Utica shales have emerged in oil and gas drilling and production?

BURDETTE: Well you’ve probably noticed that energy states are struggling right now from what has become a perfect storm. The abundance of both coal and gas has driven commodity prices into the basement. Coal is struggling. Oil is, quite frankly, at almost record lows. Of late, the state’s been struggling to keep up with the changing dynamic. We have some severance taxes in West Virginia and those have seen some pretty dramatic changes.

marcellusThat’s the bad side, but the trend lines overall have been good. I think last year we had about 13,000 West Virginians work at wages exceeding $1 billion, and wages from oil and gas jobs have increased by about a half billion dollars in just the last seven years. A lot of the change is being driven by infrastructure building. There have been a lot of gains in pipeline construction and support activities for natural gas. In the fourth quarter of 2014, employment was at 13,834, but in the first quarter of 2015, employment was down fairly significantly to about 11,666. However, the first quarter of every year is usually the lowest employment period due to seasonality.

Much Needed Natural Gas Infrastructure

But the glut and the low prices, while they haven’t exactly put the industry in hibernation, have certainly slowed down drilling. I think the larger companies are still spending significantly on their infrastructure to support the wells that they’ve drilled. All things considered, we’ve still drilled faster than we can build out [pipelines and other infrastructure]. That’s why we’ve seen the larger companies shift to investing in long-term infrastructure, and we believe that’s a solid strategy.

west-virginia-pipelinesPipeline infrastructure as a whole began to decrease after 2012, the year it peaked. That trend may reverse itself again – there is a logjam of large pipe projects including several still in play that require FERC approval. One is a $3 billion project that goes from Wetzel County to a site in Virginia, and there are several projects of that magnitude that are on the drawing board to try to get our product to market. If we can get some others approved in the course of the next twelve months I think you’ll see those numbers start to increase again.

There’s a pretty clear shift in industrial usage away from other fuels and into natural gas. We’re seeing a lot of companies, especially big users, make the conversion, including quite a few from coal to natural gas. Given the price structure and other considerations, it’s not particularly surprising. But overall, we’re still bullish and optimistic on the price of natural gas – we see it as a growth industry for us. We’ve only permitted about 10% of the fields in West Virginia, so there’s still a lot of opportunity.

The number one challenge moving forward, however, is simply getting the gas to the marketplace.

OAG360: Was the infrastructure buildout a focus of the Tri-State Shale Summit that concluded in October? Or is that mainly a general collaboration between Ohio, Pennsylvania and West Virginia?

BURDETTE: Actually, the states have never jointly collaborated on infrastructure projects. In any sense, we’d have to take baby steps on that subject.

The majority of the Tri-State Conference was really about identifying future trends and how to respond to them, but it was also about coordinating things that we know how to coordinate. We won’t ever stop competing for the next big project that comes along – there’s no sense in acting like that won’t occur, although I think all three states realize that development (like the ethane crackers, for example) have a big regional impact. We’re still looking to compete for those individually, but it’s clear that the region needs to develop collaborative efforts as far as attracting and building the work force.

west-virginia-reservesGovernor Tomblin (WV), Lieutenant Governor Taylor (OH) and Governor Wolf (PA) signed that agreement. Although it was admittedly a modest first step, it was, in fact, a first step. I think clearly developing an infrastructure that supports the region is going to be very, very important for all of us.

Ethane Storage Needed in West Virginia to Allow the State to Compete with the Gulf Coast

We talked about the needs of West Virginia to develop a storage structure, especially for ethane since it’s such a big byproduct of the natural gas. We can compete with the Gulf Coast much more effectively if we have a storage strategy that creates consistency in supply and price, along with a reliable network that can supply gas to the region. These are longer range goals, but nevertheless, you have to start developing a strategy now.

OAG360: A local newspaper named The Exponent Telegram published a piece suggesting severance taxes be raised on natural gas liquids in order to keep more revenue from West Virginia’s natural gas production in the state. Has the state administration touched base on that yet?

BURDETTE: I believe you’re referring to a study conducted by a state group that encouraged us to create a tax credit that would offset raising tax prices on ethane.

We don’t have an immediate plan to do that, and that’s because we don’t have a network of users yet. So we’re kind of cutting off our nose to spite our face, but Governor Tomblin has been very aggressive in telling our producers that we expect them to give attention to every opportunity that comes along in our region and to create value-added manufacturing that comes along with the production of the Marcellus region.

While that certainly seems to be a no brainer, the truth of the matter is that sometimes those companies have trouble putting together supply contracts for a lot of different reasons. It can be complicated to develop those contracts for five, seven or even 20 years out.

But, we’ve made it very clear to our suppliers that we expect them to give it special attention. I would say they have done so, for the most part. I don’t think we have to beat them over the head, but we’re certainly not above beating them over the head if we can’t get a cooperative contract for the region. I don’t think that’s going to be a short-term need, but it is very much on our mind. That’s an opportunity that needs to be available in our region, first and foremost.

OAG360: What’s a typical storage season like for West Virginia, considering you’re such a big storage provider to the northeast and injection rates are above five-year highs?

BURDETTE: I’m not sure this will be a big injection season, quite honestly because we’re still producing more than we can sell. Our annual delivery capacity this year is about 260 to 262 Bcf. The only state in the region that surpasses that is Pennsylvania. So we can meet our winter demands without storing gas from other states. We used to have that need, but we don’t any more. In fact, most of the gas that we sell to the northeast is still difficult to get there because of the lack of infrastructure. So, we haven’t asked for any kind of report on the injection season, but I believe the builds should be very modest.

OAG360: You touched earlier on regional jobs and employment. What have the local universities done to take advantage of those opportunities?

BURDETTE: For specifics, I’d had to defer you to President Gordon Gee’s office. But in general, West Virginia University and President Gee understand this opportunity. Mr. Gee was previously the President of Ohio State University and he knows what’s at stake. I believe he has been aggressively engaging companies and others in a discussion about the “what ifs,” and are developing several programs.

Gee Wants to Capitalize on the Shale Opportunity

On a related note, President Gee was actually at the Tri-State Shale Summit the whole time. It was funny, college presidents usually come in, give a speech and then run out the door, but President Gee sat in the back of the room for almost the entire day and he wasn’t even on a discussion panel. He just came to learn and listen – he certainly understands how significant this opportunity is, and how we have to be careful not to squander it.

OAG360: Have you and Governor Tomblin taken a stance on the Clean Power Plan?

BURDETTE: Governor Tomblin announced at the Shale Summit that we will submit a plan. It makes no sense to have the federal government impose something on us. But there is an official release on the Governor’s site that says we will conduct a feasibility study and move forward from there.

Range Resources: The Appalachia’s Early Mover Sets Stage for 2016

Range Resources: The Appalachia’s Early Mover Sets Stage for 2016

Vital Pipeline Startup will Result in Increased Margins

Range Resources (ticker: RRC) is well-established as a low cost producer (its three-year finding and development costs rank fifth among 87 peers in EnerCom’s E&P Weekly Benchmarking Report), but that doesn’t mean there isn’t room for improvement.

In the last four years, Range has exploited its Appalachia acreage (now in the neighborhood of 1.6 million acres of stacked pay potential) to line of sight production growth of 20%. It has also lowered its drilling costs per lateral foot by 60% and boosted its well estimated ultimate recovery (EUR) to among the best in the play. The company expects its Claysville Sportsman’s Unit 11H well, the 59 MMcf/d record setter of 2014, to return an estimated 15 Bcf, or roughly 2.8 Bcf per 1,000 feet of lateral. Two new wells from the same pad are currently on the drilling schedule, with the second currently being completed. Peers in the region are generating about 2.2 to 2.6 Bcf per 1,000 lateral feet, according to a note from SunTrust Robinson Humphrey.

range-eurs

“Despite drilling 38% longer laterals, our drilling costs per well have actually declined by 10%,” said Ray Walker, Chief Operating Officer of Range Resources, in a conference call. Walker explained that the first well on the Sportsman’s pad is “in the top tier of Utica wells to date… and the second well is better.”

Management believes further improvement can be made, with wells producing EURs of 17 Bcf at costs of about $16 million, as Utica drilling costs are expected to fall by 20% to 30%.

RRC management expects the 20% line of sight growth to be achieved in 2015 despite a capital pullback of 42%, with its 2015 budget allotted at $870 million. Management explains its budgets are typically front-loaded, meaning there will be less capital expended in Q4’15. Another beneficiary is the reduced drilling time, as 7.5 frac stages were completed in Q3’15 – up from 5.2 stages per day in Q3’14. Anywhere from 50 to 60 wells will be waiting on completion by year-end and will be primed to contribute to Range’s expanded takeaway options.

Mariner East I is Ready to Go

range-upliftPermitting delays pushed back the commissioning of the Mariner East I pipeline, but the project is finally approaching the finish line. RRC management expects full operations to commence by year-end, with ethane startups possible within a month. RRC has contracts to ship 20,000 barrels of ethane per day to the Marcus Hook refinery in Pennsylvania as part of a 15-year sales agreement.

An additional 20,000 barrels of propane per day will be sent to the same location and will have the benefit of market optionality, depending on the best price option. Range anticipates the propane transport market, regarding international buyers, will increase by 50% in 2016 – significantly opening up the demand window. RRC holds access to 800,000 barrels of propane storage (80% of capacity) to manage its inventory on a less restricted basis and provide upside in an expanded export market.

The natural gas liquids optionality provides uplift to margins that are becoming slimmer in the gas-heavy region of the Marcellus/Utica. “We think the worst is behind us with the realized NGL prices, especially with propane,” said Chad Stephens, Senior Vice President.

Range expects to realize a $90 million uplift in annual net cash flow if combining the net effects from its new pipeline contracts.

Antero Resources: Utica Success Pushes YoY Growth Forecast to 25%-30% for 2016

Antero Resources: Utica Success Pushes YoY Growth Forecast to 25%-30% for 2016

Utica Accounts for 25 of Antero’s 31 Drilled Wells in Q3’15; Up to 50 Deferred Completions Figure in 2016 Guidance

Management of Antero Resources (ticker: AR) believes the company can achieve year-over-year growth of 25% to 30% in 2016, based on preliminary targets released in an operations update on October 13, 2015. The significant jump is planned on top of the company’s production record in Q3’15, averaging 1,506 MMcfe/d – above its full year guidance of 1,400 MMcfe/d, which estimated 40% growth compared to 2014.

In the company release, Paul Rady, Chairman and Chief Executive Officer of Antero Resources, said, “We feel confident in our preliminary 2016 growth targets given our large inventory of drilled but uncompleted wells, as well as our industry-leading hedge book which locks in virtually all targeted 2016 production at an average all-in hedged price of $3.94 per MMBtu.”

Antero Operations Update

The company is currently running nine rigs in the Appalachian basin, with four in the Utica and five in the Marcellus. The Utica, however, received the bulk of operations in Q3’15, hosting 25 of the 31 drilled and completed wells. The disparity is expected to level off in Q4’15, with the Marcellus and Utica receiving 11 and 12 new completed wells, respectively.

The company expects as many as 2,400 “high grade” horizontal locations remain in its inventory, along with 5,331 undrilled proved probable and possible locations, offering considerable room to run. EnerCom’s E&P Weekly Benchmarking Report estimates 70% of Antero’s acreage is proved undeveloped, which is meaningfully higher than the median of 45% from 87 peer companies tracked.

About 50 wells are expected to be deferred into 2016, adding to the expected ramp-up in guidance.

Hedge Benefits

Antero was able to lock in virtually all of its 2016 production at $3.94 MMBtu (100% of target midpoint) with an expected 85% of volumes headed to favorable markets. This compares to 2015, with 94% of production hedged at $4.43/MMBtu (94% of guidance) with 71% of volumes expected to reach favorable markets.

The company reports gains of $1.5 billion since 2009, including gains in the last 26 of 27 quarters. An additional $3.1 billion in hedging gains are expected by year-end 2021. Well costs have also declined by 16% to 18% from operational efficiencies and well cost savings, and a pipeline project is on schedule for Q4’15 completion. The company also secured a 10-year agreement to provide 70 MMcf/d to the Freeport LNG project in Texas, which is expected online by the end of 2018.

The added benefits will further contribute to three-year finding and development costs that are the lowest of all companies in EnerCom’s Benchmarking Report, weighing in at just $0.66/Mcfe. The industry median, including oil companies, is $3.26/Mcfe. Antero’s asset intensity, defined as the percentage of every EBITDA dollar required to maintain flat production rates, is second only to CONSOL Energy (ticker: CNX) at 29%.

Balance Sheet Update

Antero padded its liquidity with the recent drop down of its water business to Antero Midstream in September for total consideration of $1.05 billion, consisting of $794 million in cash (less any assumed debt) and nearly 11 million issued common units. Pro forma, Antero will own 66.5% of Antero Midstream. The parent company will also receive two potential earn-out payments at year-end 2019 and 2020 if certain targets are met.

Antero Midstream gains a 20-year contract with exclusive rights to provide fresh water and disposal services at all of AR’s operations in Ohio and West Virginia. Fixed fees range from $3.64 to $3.69 per barrel. A wastewater treatment facility is also expected to be in service by Q4’17, in which AR will pay a fixed fee of $4.00 per barrel for a similar 20-year contract.

antero-midstreamUpon closing of the mentioned drop down, AR holds $3.0 billion in liquidity with $3.9 billion in debt. The company has not yet redetermined its borrowing base, which is currently set at $4.0 billion. In the Antero’s Q2’15 conference call, management said it does not anticipate a borrowing base reduction based on its ability to replace reserves and its favorable hedges.

Antero Midstream Increases Distributions

Antero Midstream (ticker: AM), meanwhile, increased its quarterly distribution for the third straight time since its Initial Public Offering in November 2014. Its new payout of $0.205 per unit is 8% higher sequentially.

The dividend payout likely stems from higher than expected EBITDA and cash flow guidance, with both being boosted by approximately $10 million in an Antero Midstream update on October 13, 2015. AM management believes the organization will benefit from the parent company’s volumes increase, forecasting a distribution growth target of 28% to 30% through 2017.

The two companies are scheduled to release their respective Q3’15 earnings on October 28, 2015, with conference calls occurring the following day.

Range Resources Maintains Production Growth, Strong Inventory of Wells Awaiting Completion by Yearend

Range Resources Maintains Production Growth, Strong Inventory of Wells Awaiting Completion by Yearend

Number of Oncoming Pipeline Projects in Place through 2017

Range Resources Corporation (ticker: RRC), one of the largest exploration and production companies in the Appalachia region, increased volumes on a quarter-over-quarter basis by 3% in its Q2’15 earnings released on July 28, 2015. The flow of 1,373 MMcfe/d are a company record and are expected to climb to 1,390 to 1,400 MMcfe/d (28% liquids) in Q3’15 – in line with RRC’s projected volumes for fiscal 2015. Capital guidance was unchanged at $870 million and about 66% has already been expended as part of RRC’s front-loaded drilling program.

Drilling efficiencies are the driving force behind the upward production trend. The company believes it can turn in line 19 more wells than previously expected, even though its current rig count of 10 will drop to six by year-end. Management said a “strong inventory of wells” will be waiting on completion by that time and will be in line to take advantage of improved regional prices in early 2016.

Range Resources will be the first company to present at EnerCom’s The Oil & Gas Conference® 20 in Denver later this month.

Source: RRC August 2015 Presentation

Source: RRC August 2015 Presentation

Incoming: More Takeaway Capacity

Jeffrey Ventura, President and CEO of Range Resources, pointed to oversupply and stressed prices as a major factor in the quarter. In the first half of 2015, Range reported revenue of $842.0 million – down 14% from H1’14, even though average MMcfe prices (including cash-settled hedges and derivatives) have dropped by 35% in the same time frame. “The second quarter traditionally brings the mildest weather of the year, which tends to amplify the pricing impact of a supply surplus,” said Roger Manny, Chief Financial Officer, in a conference call following the release.

Ventura offered optimism, adding that “The good news is that we put some arrangements in place years ago that will come to fruition later this year, which should make some of this pricing pain short lived for Range.”

Those “arrangements” are pipelines fraught with access to RRC. Included are:

  • Spectra’s Uniontown to Gas City project, expected to open on August 1, will provide 170 MMcf/d of net takeaway capacity. The takeaway accounts for 28% of RRC’s projected volumes from its southwest Marcellus operations and will ship the product to the Midwest markets. Ventura said the pipeline will increase realized prices by $1.00 under current strip pricing.
  • Sunoco’s Mariner East I, expected to open in Q3’15, will increase RRC’s access to natural gas liquids (NGL) markets. NGLs account for about 25% of overall production and the Mariner East I will have a takeaway capacity of 40 MBOPD, split evenly between propane and ethane.
  • Spectra’s Gulf Markets Expansion project, targeted for startup in Q4’16, with gross capacity of 150 MMcf/d to the Gulf region.
  • Rover Phase I, planned to start up around the same time as the Gulf Markets Expansion.
  • An assortment of expansion projects that will increase Range’s total takeaway capacity by 900 MMcf/d to target markets in the Gulf Coast, Midwest and Canada.

RRC management believes its NGL market access increases its annualized net cash flow by $90 million, not including potential propane price uplift opportunities.

Source: RRC August 2015 Presentation

Source: RRC August 2015 Presentation

Short Term Outlook

Range has heavily hedged itself in the short-term, with 85% of its gas production hedged at $3.70/MMcf and 90% of remaining liquids production at a floor price of $85.87. RRC’s hedges drop considerably in 2016 – the same time Range expects the market to improve.

“On a macro basis, good things are happening inside the Appalachian Basin,” said Ventura, explaining that Marcellus and Utica rig counts have dropped by 55% and 66%, respectively. Marcellus pipeline flows have been flat since the beginning of the year, and most of the reduced rigs have been pulled from the liquids-rich areas. Range was one of the companies who redirected its focus on the dry window, citing better margins in the constrained price environment. Ventura said: “Given the steep declines of most of these Utica liquids wells, the rebalance should happen sooner rather than later. With the drop in Utica rig count by two-thirds, coupled with the lack of hedges for 2016 and beyond by most companies, and with lower strip pricing for 2016, the Utica rig count will probably stay low for a while, which will help on the supply side.”

Other factors, including natural gas exports to Mexico and growing demand on the industrial transportation side, will right the supply/demand ship.

Positioned for the Upside

Analytics compiled by EnerCom, Inc. has routinely placed Range as one of the most cash-efficient operators in North America.

Its three-year finding and development costs of $0.73/Mcf are the fifth lowest of 84 companies in EnerCom’s E&P Weekly Benchmarking report. A new report by Wood Mackenzie says RRC has the lowest breakeven costs of any operator in the entire Marcellus region, and the company has the second greatest amount of reserves.

Management mentioned its ability to reduce year-over-year capital expenditures by 45% and still maintain a growth profile of at least 20% speaks volumes for its ability to operate in such a difficult environment. The company believes a maintenance capital of only $200 to $220 million is enough to replace its reserves.

In the near-term, RRC’s trailing twelve month debt-to-EBITDAX ratio has climbed to 3.3x in the new commodity environment, but management is not concerned. “This leverage ratio is charted territory for Range, as we have been over 3.0x on several occasions over the years,” said Manny. “Even though we no longer have a debt-to-EBITDAX loan covenant and our next annual borrowing base determination isn’t until May of next year, our stance on leverage has not changed.” A possible asset sale would bring the leverage back under the 3.0x multiple. Divestures is also charted territory, as the Marcellus/Utica leader has sold more than $3 billion in assets in the last ten years.

rrc-woodmac

Source: RRC August 2015 Presentation

Marcellus, Utica Driving 85% of Shale Gas Growth Since 2012

Marcellus, Utica Driving 85% of Shale Gas Growth Since 2012

Per well efficiencies up 2.6x in the Marcellus and 22.3x in the Utica since 2012

EIA Marcellus and Utica Natgas Growth

Increased productivity of natural gas wells in the Marcellus and Utica Shale basins is responsible for 85% of increased natural gas production in the United States since 2012, according to the Energy Information Administration (EIA). Natural gas from shale basins is now responsible for 56% of U.S. dry natural gas production. Collectively, shale production from the Marcellus and Utica regions increased by 12.6 Bcf/d from January 2012 to June 2015, making them the driving force behind overall growth.

The EIA’s Drilling Productivity Report (DPR) tracks total production and rig productivity in major U.S. basins, illustrating how increased efficiencies have pushed production higher. In the Marcellus, new-well production per rig in January 2012 was 3.2 MMcf/d. By July 2015, that number increased 160% to 8.3 MMcf/d. The trend of new-well production per rig also follows the trend in overall production, which increased to 16.5 Bcf/d in July 2015 from 6.3 Bcf/d at the beginning of 2012.

marcellus-efficiency

New-well production per rig in the Utica saw an even more significant increase during the same time period, increasing by a factor of 2230%. In July 2015, new-well gas production per rig in the Utica Shale was 6.9 MMcf/d, compared to just 0.31 MMcf/d in January 2012. Overall production in the Utica increased by a factor of 1730%, reaching 2.6 Bcf/d in July of this year from 0.15 Bcf/d in January 2012.

Utica

According to the EIA, the increases in natural gas production from these two plays were largely the result of four factors:

  • Greater use of advanced drilling techniques
  • Increased number of stages used in hydraulic fracturing operations
  • Increased use of techniques such as zipper fracturing
  • Use of specific components during well completion that aid in increasing fracture size and porosity of the geologic formation being targeted

Growth expected to continue

Goldman Sachs reported that the Marcellus/Utica region will continue to account for 85% of net production growth in the U.S. from 2014 to 2018, continuing the basins’ trends as the driving force behind natural gas production growth in the United States.

Goldman believes the buildout in the Utica will result in $21 billion of investment to reverse pipelines and build new pipelines from Appalachia to support substantial changes in gas flows for supply to meet demand. For a more in-depth look at the Utica, see OAG 360’s full coverage of one of the most prolific plays in the U.S. here.

MarkWest Continues Growth Plans Despite Lower Prices

MarkWest Continues Growth Plans Despite Lower Prices

$1.5 to $1.9 billion in 2015 growth capital

Denver based MarkWest Energy Partners LP (ticker: MWE) remains focused on growth, even as oil prices remain low. A recent presentation from the company says the company currently has 20 major projects under construction, and forecasts $1.5 to $1.9 billion in capital investment for 2015.

The company’s focus on pipelines and associated assets has helped to keep it more insulated from the oil price decline than most E&P companies. The company has nearly 4,700 miles of pipelines, 6.0 Bcf/d of gas processing capacity and 379 MBOPD of fractionation capacity. 90% of the company’s 2015 net operating margin is fee based, and the company has long-term agreements with over 160 producers.

MarkWest

MarkWest still sees opportunity in Ohio despite current prices. The company is finalizing three major plant expansions in the state and a fourth plant with 200 million cubic feet of extra capacity that will be added to its Seneca processing complex in Noble County, reports the Denver Business Journal.

“Given the market conditions currently, this will give us plenty of capacity to meet all the immediate needs,” said David Ledonne, vice president of MWE’s Utica and Appalachia operations.

The company currently has $1.1 billion in liquidity according to its corporate presentation. MWE’s debt to market cap is well below its peers in EnerCom’s MLP Weekly at 37% compared to the group’s median of 57%.

Focus on the Marcellus

MarkWest Growth Capital Pie Chart

Source: MarkWest

Of the company’s projected $1.5 to $1.9 billion of 2015 capital investment, 76% ($1.1 to $1.4 billion) is earmarked for use in the MarkWest’s Marcellus segment. MWE anticipates 67% of its 2015 forecasted operating income coming from the Marcellus where the company’s operating margins are 94% fee based.

Currently the company has 1.0 Bcf/d of gathering capacity in the Marcellus along with over 3.1 Bcf/d of cryogenic processing capacity, 106 MBODP of C2+ fractionation and 180 MBOPD of C3+ fractionation capacity, 140,000 barrels of natural gas liquids storage capacity and access to over 900,000 barrels of shared third-party propane storage. MarkWest has an additional 1.8 Bcf/d of cryogenic processing capacity, 141 MBOPD of C2+ fractionation and 60 MBOPD of shared C3+ fractionation capacity currently under construction.

June 22, 2015 - 6:53 pm Midstream, MLPs, Oil and Gas 360 Articles
Range Resources Continues Record-Setting Trend in Q1’15 Results

Range Resources Continues Record-Setting Trend in Q1’15 Results

Leading Natural Gas Producer not Slowing Down

Range Resources (ticker: RRC) maintained its 20% to 25% annual line-of-sight growth strategy in its Q1’15 results, announcing a new production record of 1,328 MMcfe/d in the quarter. Volumes for 2015 are expected to average 1,394 MMcfe/d (30% liquids) for the fiscal year based on the company’s guidance of 20% growth, even though its capital expenditures are down roughly 45% compared to 2014.

Revenues for the latest quarter totaled $462.6 million with net income reaching $27.6 million, or $0.16 per share. Total sales of $422.9 million decreased by about 10% compared to Q1’14, even though the company’s average realized prices were 28% less due to the commodity fallout. Production increased by 26% over the same time frame and unit costs dropped by 15%.

The company has budgeted $870 million for expenditures in 2015 but believes the number may decrease due to reduced service costs.

rrc breakeven

Source: RRC April 2015 Presentation

Gas on the Rebound

Jeff Ventura, President and Chief Executive Officer of Range Resources, opened up the company conference call with a macroeconomic perspective on natural gas and the role of the Appalachia region. Considering Range discovered the Marcellus Shale and has been one of the longest tenured operators in the northeast, its words hold significant weight.

“We believe that over the last year, the U.S. gas market typically has been oversupplied by about 2 to 4 Bcf/d,” said Ventura. However, RRC believes demand is expected to increase by about 2 Bcf/d in 2015, followed by annual growth demand of 3 to 4 Bcf/d from 2016 to 2020. Overall, about 20 Bcf/d of incremental gas demand will be realized by 2020. Even the Energy Information Administration has projected the United States will become a net exporter of natural gas by 2017.

Ventura then broke the supply side into two segments, with gas production coming from both oil wells and gas wells. An estimated 16 Bcf/d of recent production is estimated to come from oil wells, with half of that number associated with shale operations. “The first year declines of unconventional resource oil wells are much steeper than gas wells and typically are in the 70% to 90% range,” said Ventura. “Given the continuing steep drop in the rig count and typically steep first year declines of those oil wells, I believe that we’ll see a production response in the second half of this year.”

Ventura explained this downturn is different than the one in 2008, especially since horizontal rigs consisted of about 30% of the fleet that year, as opposed the current makeup of approximately 75% in the latest Baker Hughes rig count update. The efficiencies and pad drilling techniques have improved, but the nature of the rigs will play a role.

“The operators dropped their vertical rigs first because they were not driving production,” said Ventura. “Today, there are no vertical rigs drilling the Marcellus or Utica, so decreasing the rig count should have an impact.”

Source: RRC April 2015 Presentation

Source: RRC April 2015 Presentation

Record Setters

Range’s prominence in the Appalachia was compounded last year with its record-setting Utica well (87.5% working interest) in Washington County, which returned an initial 24-hour rate of 59 MMcfe/d in Q4’14. The well was brought online in January and, despite constrained rates, has returned 1,200 MMcf to date. Three additional Utica wells are planned in 2015 and the first has already been spud.

In a note, Stifel said RRC’s estimates of gas in place in the region are as much as 40% higher than that of its neighboring operators. Ray Walker, Chief Operating Officer, backed up Range’s confidence in the call by saying, “The rock rules and our results indicate we’ve captured some of the best rock in North America.”

On the Marcellus side, a well in the wet gas area of Washington County returned a 24-hour rate of 43.4 MMcfe/d – a Marcellus record, according to the company. The Washington County region and its nearby acreage will be the focal point of Range’s 2015 operations, and 35 of the 38 wells turned to sales in the quarter are based in the Southern Marcellus region. The Northern Marcellus Shale division will run one to two rigs for the remainder of 2015 and anticipates turning 11 more wells to sale for the remainder of 2015. A total of 150 wells are expected to be turned to sales in 2015, which would amount to 112 more wells being placed online.

UBS Financial Services points out that RRC’s unbooked resource base is seven times greater than its proved resource base of 10.3 Tcfe (even before considering Utica potential), and Range management said it still has “thousands and thousands” of future wells in its portfolio.

Appalachia Results

Range’s ability to develop its wells at a low cost (its three year finding and development costs per Mcfe ranks fifth out of 88 companies in EnerCom’s Weekly Benchmarking Report) is a testament to its advancements in completion techniques and well designs. In the call, management said RRC’s estimated ultimate recovery (EUR) per 1,000 foot of lateral in the southern part of the play is the best among its peers, while its overall EUR/lateral foot in the entire Marcellus region is second only to Cabot Oil & Gas (ticker: COG). Its Nora Field in Virginia, acquired from EQT Corp. (ticker: EQT) as part of an acreage swap in Q2’14, are performing at their best rates in 20 years and receive a price premium due to their location on the southeast Atlantic Coast.

In a note covering the release, SunTrust Robinson Humphrey said: “We believe Range continues to deserve a premium versus the peer group given its solid production growth along with likelihood the company becomes cash flow positive relatively soon and should remain so thereafter.”

rrc costs

Source: RRC April 2015 Presentation

Market Utilization: NGLs

Range management said the richness of its gas combined with favorable contracts allow the company to utilize its resources in several ways. Previous information has been provided on its ethane market, and 80% of the company’s 2015 ethane flow is tied to different indices than Mont Belvieu.

Range also upped its stake in the international LNG market, securing an overseas buyer for a long-term agreement of 50,000 Mmbtu/d. The company now has 200,000 Mmbtu/d in contracts. The Marcus Hook harbor facilities, designed to save RRC $0.20 per gallon of propane, is expected to be operational in Q3’15 and will be utilized on the company’s 20 MBOPD of propane volumes. The arrangement is expected to increase RRC’s annualized cash flow by $90 million. Stifel estimates this could result in a NGL price uplift as high as 25%.

Cash in Mind

RRC is heavily hedged in 2015, with more than 85% of total volumes locked in at prices of $3.77/Mmbtu and $87.44/barrel. Close to half of its anticipated 2016 production (about 700 MMcfe/d) is already hedged, with average liquids prices of $70.54/barrel.

The company also switched its bank facility from debt-to-EBITDAX to a EBITDAX-to-interest-expense covenant, a setup that will save money and improve cash management, according to Chief Financial Officer Roger Manny.It was actually a pretty easy conversation as evident by the fact that all 29 banks unanimously approved the change,” he said. “But when the banks do the borrowing base determination, they basically take all your cash flow until your next review date and toss it out…The borrowing base is their primary tool to manage leverage and the reason is pretty simple. It’s a forward-looking test…The debt-to-EBITDAX covenant, that’s a rearview mirror test. So it’s really not as applicable to managing leverage over time.”

The EBITDAX to interest expense covenant of 2.5x is supported by an existing $3 billion borrowing base. The ratio of the present value of proved reserves to total debt covenant of 1.5x will apply until Range has two investment grade ratings. Current liquidity is approximately $1.2 billion. Management added that most of the production volumes increases are backloaded for the end of the year, an attribute that will help the company hit 2016 with a running start – the same time frame in which management expects prices to rebound.  

In October, Oil & Gas 360® published an article entitled “How One Man’s Decision Cracked Open an Energy Revolution: The Marcellus Turns 10.” The article is based on a detailed account from Jeff Ventura about Range’s 2004 discovery of the Marcellus shale play.

rrc trans

Source: RRC April 2015 Presentation

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

Cabot Oil & Gas Q1’15 Results Driven by Efficiencies in Two World Class Resource Plays

Cabot Oil & Gas Q1’15 Results Driven by Efficiencies in Two World Class Resource Plays

Cabot Oil & Gas (ticker: COG) continued its rise in production volume in its Q1’15 results, reporting production of 171.4 Bcfe in the quarter. The volume represents increases of 15% and 43% compared to Q4’14 and Q1’14, respectively. Total revenues of $464.7 million amounted to net income of $40.2 million, or $0.10 per share.

Volumes are expected to be reduced in the upcoming quarter due to the current commodity environment. The average sales price in Q1’15, including hedges, was $2.46 – more than one-third below the average price of $3.74 in Q1’14. At $2.45/Mcf, COG still generates an 80% internal rate of return. Realized gas prices traded at $2.23 in the quarter, representing a $0.75 discount to NYMEX prices compared to a $0.59 discount in Q1’14. Total unit costs (including financing) of $2.33/Mcfe are 12% lower on a year-over-year comparison.

Global Hunter Securities said the guidance for Q2’15 “likely mutes” the Q1’15 volumes, which beat street estimates. When discussing the forecasted production decrease, Dan Dinges, President and Chief Executive Officer of Cabot Oil & Gas, said, “We think, from a prudency standpoint, it was our best interest to protect shareholder assets and not to compromise our margin to the extent that the current price would yield.”

COG’s borrowing base was increased to $3.4 billion (from $3.1 billion) prior to the end of the quarter and lender commitments have climbed to $1.8 billion (from $1.4 billion). The company had $265 million in outstanding borrowings at the end of the quarter. Net debt at the time of the release was $1,863 million, amounting to a debt to market cap percentage of 13%. By comparison, 86 peer companies in EnerCom’s Weekly Benchmarking Report have a median debt to market cap of 56%.

A Marcellus Leader

Cabot has historically returned value in the Marcellus region due to its efficiency, low finding and developing costs ($0.68/MMcf on a trailing three-year basis, the third lowest in EnerCom’s Benchmarking Report) and high return wells (COG had 17 of the top 20 cumulative producing Pennsylvania wells in 2H’14). The company drilled 26 Appalachia wells at an average of 15 days apiece in Q1’15, marking its most efficient quarter to date. The faster drilling times have resulted in drilling and completion costs declining by as much as 20% when compared to 2014. Overall, the wells are tracking as much as 50% above type curves.

Cabot plans on running three Marcellus rigs for the remainder of the year and expects gross volumes to average 1,550 to 1,600 MMcf/d in Q2’15 – about 9% below volumes from Q1’15 but a reiteration of previous guidance. In the conference call, Dinges said, “In light of our expectations for continued weakness throughout Appalachia during the summer months, we do often reevaluate our program and may consider delaying completions as we await a more favorable price environment in the future.”

A total of 45 Marcellus wells are expected to be drilled in its 2015 drilling program. Based on production data from the state of Pennsylvania, COG was the top producer in the first two months of 2015, even though the E&P has never run more than six rigs in the region.

cog-marcellus

Constitution Update

Cabot’s access to the Constitution Pipeline was a very popular topic in its Q4’14 conference call, and Dinges provided an update in the call on April 24. He said:

“The project remains on its current schedule for end service during the second half of 2016. The New York DC is currently finalizing responses to the comments received during the public comment period. Constitution now has possession of 100% of all the tracks necessary to begin construction. Constitution is working towards the finalization of New York State permit by the end of the second quarter, and FERC implementation plan is expected to be filed by Williams during the second quarter. Based on the progress during the last few months, we continue to optimistic that construction can begin mid-summer, assuming all these permits are in hand.”

Barclays estimates the addition of Constitution could add 15% to 20% in cash flow as a result of higher volumes and lower differentials. The pipeline will be filled immediately upon commissioning.

Eagle Ford Ramping Up

Production from its South Texas assets climbed 19% compared to Q4’14, reaching an average of 17,831 BOEPD. COG placed 20 wells online in the quarter, with 10 of the wells outperforming production rates from the previous operators. Similar to the Marcellus, drilling efficiencies are also on the rise in the Eagle Ford with drilling days declining to an average of just 10.6 per well. Completion costs have dropped by roughly 25% compared to 2014.

cog-crociTwo rigs are currently running in the play with expectations of reducing one by the end of May. A total of 45 net wells are expected to be drilled within the fiscal year, and COG management says the company can generate 50% rates of return at $65/barrel.

2015 Forecast

The company plans on spending $900 million in its 2015 capital plan, down nearly 40% from 2014’s total of $1,479 million. Its growth guidance of 10% to 18% remains intact, which would place fiscal 2015 volumes at greater than 600 Bcfe. Capital One Securities believes hitting the upper end of guidance “looks very achievable” based on a “very strong Q1 production beat.”

Since 2012:  Proved Reserves Double, Marcellus Completion Costs Cut by Half

The room for growth is significant – COG estimates 4,300 drilling locations remain on its acreage and will add to its proved reserve base, which has nearly doubled since 2012 to reach 7.4 Tcfe. Marcellus completion costs per Mcfe have halved in the same time frame.

KLR Group provided a very positive review in a note following the earnings call.”Given the lowest capital intensity in the industry, Cabot should generate a ’15 capital yield of ~110% versus the industry median ~85,” the company said. “A clear illustration of COG’s differential capital productivity is the company’s ability to achieve competitive production/CFPS growth (’15E-’17E) spending inside cash generation; while Marcellus peers spend at least 20% in excess of cash generation.”

Asset intensity, defined by EnerCom Analytics as the percentage of EBITDA necessary to maintain production, is 29% – well below the E&P median of 61% and the seventh lowest overall. The low costs allow Cabot to adjust rather quickly if prices recover in the short term. “Keep in mind that the capital intensity necessary for us to ramp up our volumes is minimal,” said Dinges.

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

Appalachia Production is Red Hot, but the Henry Hub is Still King

Appalachia Production is Red Hot, but the Henry Hub is Still King

The meteoric production rise of the Marcellus and Utica Shales has shifted the playing field of the natural gas market and changed the United States energy landscape. While the recent commodity swing has finally forced U.S. oil production to least plateau (for the time being), the Appalachia has delivered consistent year-over-year growth ever since horizontal drilling truly took off in 2008. The Marcellus/Utica now accounts for 40% of gas production from the seven major U.S. regions and is projected to continue to grow.

The emergence of the Appalachia has reduced trading volumes at the Henry Hub landing spot by 70% in the last five years, leading to editorials pondering if Marcellus production would unseat the traditional go-to spot price holder. Pennsylvania alone increased its dry gas production to 8.8 Bcf/d in 2013, compared to 0.74 Bcf/d in 2009. In the same time frame, dry gas production from the Federal Offshore Gulf of Mexico has been cut in half to 3.4 Bcf/d. The dramatic swing has resulted in a handful of editorials pointing out the change in power.

“How important is the Henry Hub as a price proxy for the Eastern US? My thinking is that, before long, it won’t be very important at all,” Teri Viswanath, director of commodity strategy for natural gas at BNP Paribas, told Reuters in September.

A December 2014 article by Forbes titled R.I.P. Henry Hub? Marcellus Shale Shifts Geography of Natural Gas Markets, said: “The rise of a new producing region combined with production declines in traditional areas of production is shifting historical flow patterns. It is only a matter of time before the market follows.”

slide1

Down but not Out

Patrick Rau, Director of Strategy and Research for Natural Gas Intelligence, acknowledged the radical shift in production areas, but says the chances of the Appalachia overtaking the Henry Hub are “virtually nil.” In a webcast on April 7, 2015, titled “Will the Marcellus/Utica Overtake the Henry Hub?” Rau pointed to several factors that the dominant landing price has been and will continue to set the bar on gas prices. He points out that Henry Hub prices have remained consistent despite the flow of production from the Appalachia, and the only impact that those volumes have had on other spot prices is added volatility – the majority of which have pushed into other markets in the northeast and in Chicago.

“Appalachia is not the national pricing point,” he said. “It still has only 20% of production and is also on the lower end of pricing. I believe it still serves as a reasonable proxy for the area.”

Rau also said the Marcellus/Utica will not be able to sustain the rapid level of growth, particularly due to the headwinds from the new commodity environment. Natural gas production has also outpaced demand in recent years, with respective increases of 4.4% and 2.0%, which led to the gas price slide in the first place.

“New Competitors”

The growth of the Appalachia is remarkable, but the eventual production slowdown and competition from other basins will make the Henry Hub a standout price point once again. The Haynesville, in particular, will be a region that Rau expects to support future growth at the Hub.

“The Haynesville has lots of undeveloped wells, it’s dry gas so processing is minimal, there’s plenty of takeaway capacity and potential for recompletions,” he explains, adding that the proximity of the play to the Gulf of Mexico and several liquefied natural gas (LNG) terminals makes it even more attractive. “By the end of 2020 we believe LNG exports could account for 10% of all U.S. demand.”

Rau reminded the audience that there are already too many physical and financial contracts tied to the Henry Hub, and the landing price could become the pricing record for international trade once LNG exports turn online.

Wei Chien, Founder of Observ Commodities, closed the webinar with the old phrase of: “It is not the strongest of the species that survives, nor the most intelligent, it is the one that is most adaptive to change.”

Henry Hub certainly appears to have the versatility and reliability to remain the key landing spot, but don’t believe the Appalachia is set up for a decline. Several pipeline projects are scheduled to come online in late 2016, alleviating the regional spread that has traditionally kept Appalachia prices as much as 25% below HH prices.

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication.

April 7, 2015 - 6:57 pm Commodity Pricing, Fracing, LNG, Oil and Gas 360 Articles
Oil & Gas 360 Energy News

Southwestern Sells Non-Core Assets, Bumps 2015 Divesture Totals to $718 million

*Update*

Just one day after selling select gathering assets in the Appalachia for $500 million, Southwestern Energy (ticker: SWN) announced the $218 million sale of conventional operations in East Texas and the Arkoma Basin. Both deals were completed with private companies and are expected to close in Q2’15.

The deals, which total $718 million, fall in line with SWN’s intended divesture plan of $600 to $800 million. In its Q4’14 conference call, SWN management said it expected to reach agreements on both properties no later than Q2’15. The East Texas/Arkoma assets held a listed PV-10 value of about $173 million and were not receiving any part of the company’s $2.0 billion capital plan.

“Combined with the already announced divestiture of our northeast Pennsylvania gathering system, this transaction achieves the net divestiture proceeds targeted as part of the acquisition financing plan,” said Steve Mueller, Chairman and Chief Executive Officer of Southwestern Energy, in a press release. In a previous announcement, Mueller said the gathering system sale placed the company “Well on our way to achieving the $600 to $800 million in divesture proceeds as part of the acquisition financing plan.”

All proceeds from the divesture plan will be used on a $500 million term loan (taken out in December) and the remainder on the company’s revolver, which had $300 million drawn at year-end 2014.

*Original*

Southwestern Energy (ticker: SWN) has sold its gathering assets in two northeastern Pennsylvania counties for proceeds of $500 million, the company announced on March 19, 2015. The transaction is a significant step to completing the company’s divesture plan, as part of financing the sizable purchases last year. The buyer, privately held Howard Midstream Energy Partners (HEP), receives approximately 100 miles of natural gas gathering pipeline with 600 MMcf/d of capacity. The assets are HEP’s entry into the Marcellus Shale, as the company previously operated only in South Texas. An office will be opened in Pennsylvania once the deal is finalized in Q2’15. Its footprint in the Eagle Ford, Escondido, Olmos and Pearsall formations include 500 miles of pipeline, a processing plant and liquid storage terminal.

Southwestern: “Well on our Way”

Southwestern was one of the most active E&Ps on the acquisition front last year, spending more than $5.6 billion to lock down nearly 500,000 net acres in the Appalachia region. In the Q4’14 conference call, Mueller said some pieces of its recent purchases “will be possible disposition candidates,” but the sales would likely not occur until late-2015 at the earliest. “We actually have a gas storage field in Arkansas that under some previous agreements we couldn’t do anything with until about June of this year. You might see us sell that one and some other small assets. Stay tuned on that one and watch the year as it plays out.”

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

Cabot Oil & Gas Banks on Low-Cost Operations, High-Return Marcellus Wells in Q4’14 Earnings

Cabot Oil & Gas Banks on Low-Cost Operations, High-Return Marcellus Wells in Q4’14 Earnings

Cabot Oil & Gas (ticker: COG), a large-cap E&P with operations in the Marcellus and Eagle Ford shales, reported company records for production and net income excluding selected items in its year-end 2014 earnings release. Full-year production in 2014 was 531.8 Bcfe – an increase of 29% compared to 2013, including liquids production of 3,961 MBO – 23% higher than 2013.

2014 operating revenues climbed to $2,173 million and net cash from operations reached $1,236 million, representing year-over-year increases of 24% and 21%, respectively. Fiscal 2014 net income was $104.4 million ($0.25 per share), but was higher than $325.0 million for the first nine months of 2014 before the commodity downturn. If considering the Net Income Excluding Selected Items table issued in the news release, COG’s 2014 income was $404.5 million, which is 36% above 2013’s total of $298.1 million.

The company reported total debt of $1,731 million, equaling a debt to market cap ratio of 44%. In EnerCom’s E&P Weekly Database for the period ended February 13, the median ratio for 89 covered companies is 58%, meaning COG is still on the low end of the debt spectrum. Its drilling efficiencies have supported its balance sheet: COG has the third lowest three-year finding and development costs of all companies listed on the Weekly.

Its asset base also provides additional room for cash flow, as evidenced by its asset intensity (defined as the percentage of EBITDA necessary to maintain production) of 32%, meaning $0.68 on every dollar can be reinvested into growth or paying off debt. The median asset intensity in EnerCom’s Weekly is 56%. Discretionary cash flow in 2014 increased by 16% year-over-year to reach $1,271 million, and the company committed $139 million to repurchase 4.3 million shares throughout 2014.

Dan O. Dinges, Chairman, President and Chief Executive Officer of Cabot, did not rule out potential acquisitions in the near-term. “A lot of opportunity occurs to those that have a strong balance sheet and optionality in a down market,” he said in a conference call following the release. “We’re certainly one of those companies.”

Cabot’s Stakehold: The Marcellus

Operations in the Appalachia attributed for 93% of all volumes in fiscal 2014 and produced an average of 1,491 MMcf/d in Q4’14. New wells are also coming online, as the company drilled 75 of its 200 gross wells in the quarter. Its 2014 drilling program completed 19 more gross wells than it did in 2013, and 100% of the operations were successful. COG’s efficiency in the region is well documented: Pennsylvania’s top 16 producing wells (cumulatively) for 2H’14 all belonged to Cabot, according to data from the state’s Department of Environmental Protection.

COG’s proved reserves also increased for the fifth straight year primarily through its ongoing Marcellus operations. The company reported 7.4 Tcfe of proved reserves at year-end 2014 – an increase of 36% compared to the prior year. 96% are natural gas, while 61% are classified as proved developed producing assets.

The Eagle Ford is Up-and-Coming

COG doubled its Eagle Ford production on a year-over-year basis, reaching average volumes of 14.8 MBOEPD (96% liquids) in Q4’14. Contributing to the volumes were 20 wells placed online in the quarter, with four of the wells (downspaced to 300 feet between laterals) combining for 210 MBO in their first 60 days of production. Plans for 2015 include drilling approximately 45 wells, placing 40 to 45 online and have 20 total wells waiting on completion by year-end.

“A More Measured Approach”

Cabot plans on dialing down its drilling operations in 2015, reducing its Marcellus rig count to three from its current level of five by the end of Q2’15. COG plans on running one rig in the Eagle Ford, down from its current count of three. In the call, Dinges said the reduction is “a more measured approach” to the commodity environment.  “However, given the low-capital intensity of our operations, we can remain flexible to accelerate our pace of operations if market conditions and new takeaway capacity warrant,” he added.

Average well costs in the Marcellus and Eagle Ford range from $6.0 to $6.5 million, and the company plans on drilling and placing online 110 to 115 wells in fiscal 2015 (70 in the Marcellus). When asked about Eagle Ford activity, Dinges said: “We’re not impressed with the returns at $50 [per barrel]. At $60, $65, certainly, it has a return profile that starts getting attractive again.”

In relation to the drilling program, COG’s total 2015 expenditures will consist of $900 million (down from October’s guidance of $1.53 to $1.60 billion), with 80% directed for drilling and completions. The Marcellus will receive the lion’s share of the capital, with a $432 million budget (60%) for D&C. Despite the tightened purse strings, Cabot still believes it can achieve production growth of 10% to 18%, which would place full-year midpoint production at greater than 600 Bcfe. Approximately 28% of its natural gas production is hedged.

Constitution Pipeline

The Constitution Pipeline was a popular topic in COG’s conference call. The pipeline, which management believes will take as much as 0.5 Bcf/d of Cabot’s production to new markets and price points, is awaiting the final permits needed to move forward.  Public commentary will end on February 27, 2015, and COG and its partners will immediately move forward by applying to the Federal Energy Regulatory Commission for a construction permit. Williams (ticker: WMB) will be the operator of the pipeline.

Dinges said COG’s backlog of wells, which is expected to be in the range of 40 to 45, is by design. Regarding the impending pipeline, he said: “Those wells that we’ll have by the end of 2015 will be able to build our volumes into the expected commissioning date of 2015… We expect continued efficiency gains in our 2015 program, which I think is going to translate into maybe higher IPs and higher EURs which would allow for a more rapid increase in the amount of deliverability leading up to Constitution.”

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

 

Southwestern Energy Continues Appalachia Acquisition Spree with $394 Million Deal

Southwestern Energy Continues Appalachia Acquisition Spree with $394 Million Deal

One day after closing on its $4.975 billion acquisition for 413,000 net acres in West Virginia and southern Pennsylvania, Southwestern Energy (ticker: SWN) spent another $394 million to increase its working interest. On December 23, 2014, SWN secured a 20% stake of Statoil’s (ticker: STO) remaining working interest, which equates to 30,000 acres and 29 MMcfe/d net to Southwestern.

The latest addition is an extension of the multi-billion dollar purchase from Chesapeake Energy (ticker: CHK) in October. Per the original terms, the average working interest of the acquired properties was 67.5% at the time of the release. According to SWN, the latest acquisition boosts its footprint by “approximately 5.8% to approximately 73.0%.”

The $4.975 billion purchase was revised downward from the initial price of $5.375 billion due to recent commodity price declines. Nearly all of the returned prices were spent in the latest deal, so, in a way, this could be seen as a bonus of sorts by adding a 5.8% working interest for the price originally planned.

The newest addition is the third in the last three months and the second in December alone. All of its recent deals have expanded SWN’s presence in the Marcellus/Utica region.

Date Seller Price ($MM) Net Acreage Net Production (MMcfe/d)
Oct. 16 Chesapeake

$4,975

413,000

336

Dec. 23 Statoil

$394

30,000

4

Dec. 2 WPX Energy

$300

46,700

50

Southwestern Total

$5,669

489,700

390

Not including its latest acquisitions, SWN reported production of approximately 2,100 MMcfe/d in its Q3’14 results. The Marcellus produced approximately 730 MMcfe/d in the quarter so the pro forma assets, assuming production remains constant, will increase by 54% to 1,121 MMcfe/d. Overall production would stand to increase by approximately 18%.

Date Seller

Price/Acre  ($MM)

Price/Flowing Mcfe

Oct. 16 Chesapeake

$13,014

$15,997

Dec. 22 CHK (revised)

$12,046

$14,806

Dec. 23 Statoil

$13,133

$98,500

Dec. 2 WPX Energy

$6,423

$6,000

Southwestern Total

$11,576

$14,535

In a press release, Torstein Hole, Statoil senior vice president and US onshore head, said: “The transaction reduces Statoil’s non-operated holdings at an attractive price, demonstrating the value of the Marcellus assets. Our new partnership with Southwestern Energy provides us with an opportunity to maximize the value of an important growth asset in our US onshore portfolio. Southwestern is a very dynamic operator that will maximize the value and return.”

Statoil first entered into the joint venture with Chesapeake in 2008. In 2010, STO paid $253 million to acquire 59,000 net Marcellus acres ($4,324/acre) in 2010. A total of nine rigs were running in the region at the time of its Q3’14 earnings release in October.

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

Rice Midstream Partners Braves Difficult Commodity Market with IPO

Rice Midstream Partners Braves Difficult Commodity Market with IPO

Rice Energy (ticker: RICE), an independent E&P focused purely in the Appalachia, commenced an initial public offering (IPO) for its midstream unit on December 17, 2014. Rice Midstream Partners LP will trade on the New York Stock Exchange under the ticker RMP. Rice was a privately held company less than one year ago and now has two entities listed on the NYSE, following an IPO in January and the completion of its midstream spinoff today.

Rice management has spoken of its MLP intent for the past few months, including during its Q2’14 conference call in August.

“We believe MLP structure is more suitable for these assets’ risk and cash flow profile and, therefore, would be more appropriately eliminating these assets’ value,” said Grayson Lisenby, Chief Financial Officer, in its most recent Q3’14 conference call. “The MLP also provides a better vehicle to fund midstream development, pursue third-party opportunities and monetize Rice Midstream assets while retaining operational control. And we think operating our midstream has been a huge differentiator for our upstream development to-date.”

Rice Midstream Debut

RMP offered the public 25 million common units with an additional 30 day option for 3.75 million units, amounting to 43% and 50% of the company, respectively. Rice Energy will retain ownership of the remaining interest. The price was expected to be $19.00 to $21.00, but was later revised to $16.50 and resulted in net proceeds of $383.7 million ($413.9 million if the additional units are allotted).

The units closed at $16.30 in its first day of trading.

Lisenby detailed the MLP’s assets in the Q3’14 call, saying: “Our announced MLP will fund the dropped Pennsylvania gathering assets with its own credit facility. And second, all retained midstream assets consisting of Ohio gathering, Pennsylvania and Ohio Water will be placed under a new wholly-owned midstream entity and funded with a new midstream credit facility. This midstream entity will charge Rice E&P a gathering fee, similar to what we’ll have in place with the gathering assets designated for the MLP.”

The midstream assets acquired by Rice within the last year has opened up exposure to Gulf Coast pricing. Management said Appalachia gas spot prices traded at a $1.50/Mcf discount to the Henry Hub in September, but its transportation services allowed each Mcf to be shipped for $0.45/Mcf, resulting in uplift of more than $1.00/Mcf. The company expects 50% of its volume to receive Gulf Coast pricing in Q4’14, increasing to 60% of volumes in 2015.

Capital One Securities issued a review of the Marcellus/Utica in a note on December 17, 2014, following their conference in New Orleans. It reads: “The precipitous decline in oil pricing that preceded the conference continued throughout its duration. As a result, gassy names in the Utica and Marcellus began to look more attractive than their oily peers on a relative basis. While oil producers have been and will continue to be slashing CAPEX and corresponding growth plans, names like GPOR, RICE, REXX, and RRC can continue to post reasonable (20% – 25% growth for RRC) and in some cases tremendous (around 100% for GPOR and RICE) growth for 2015. Differentials in the play put it at a disadvantage to Rockies producers for existing production, but for companies with sufficient firm transport in place the impact is muted. Pricing and take-away from the Northeast basins will continue to drive the bus for another couple of years, but with giant wells like RRC’s most recent result in PA’s deep Utica (59 MMcfe/d IP) the economics here will win out over time.”

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

December 17, 2014 - 6:26 pm Midstream, MLPs, Oil and Gas 360 Articles
Most Economic Basins at Today’s Oil/Gas Prices

Most Economic Basins at Today’s Oil/Gas Prices

In October, OAG360 examined the internal rate of return (IRR) in two of America’s key shale basins – the Eagle Ford (EF) and Bakken. EnerCom’s analysis showed the Eagle Ford is more economic than its rival basin by a handful of percentage points, no matter the price.

Oil prices for West Texas Intermediate crude have hovered around the $75 per barrel mark for the past week, but both basins will still provide upside if the price slips to $70 by the end of the year. In a $70 per barrel environment, the EF and Bakken provide IRRs of 12.9% and 9.0%, respectively.

A report by KLR Group, released on November 19, 2014, supports the assessment of the Eagle Ford’s E&P-friendly economics. The report says the breakeven price for Eagle Ford wells is $60 – below breakevens of the Permian, Niobrara and Bakken, which can range from $68 to $74. KLR cites the EF’s lower capital intensity ($30/BOE) and “relatively high oil price netback ($2.50 below NYMEX) drive this advantaged outcome.”

Pages from 813b2961-3536-4788-ae98-90fbd27d7623

Marcellus Leads the Gas Plays

Gas markets have already withstood the price cut rollercoaster that is currently plaguing oil, but the economics are still viable in the majority of large basins. Wet gas is the most economic, with breakevens of the wet Marcellus and wet Utica at $2.50 and $3.10 per thousand cubic feet (Mcf) respectively. Dry Marcellus gas is next in line at a $3.50 per Mcf breakeven. The Haynesville, Fayetteville and Barnett are more capital intensive, requiring prices ranging from $3.75 to $4.25 per Mcf. The latter three plays all have a higher price netback than the Appalachia region, which further proves the strength of the Marcellus/Utica plays.

NYMEX December natural gas traded at $4.40 per Mcf today.

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

November 19, 2014 - 6:46 pm Commodity Pricing, Oil and Gas 360 Articles
Sell the Company, Export LNG, or Build an NGV Market?

Sell the Company, Export LNG, or Build an NGV Market?

Philadelphia tries to decide what to do with PGW

The city of Philadelphia has been wrestling with a decision over what to do with city owned utility Philadelphia Gas Works (PGW).

Mayor Michael Nutter spent two years, and PGW spent more than $2 million, in order to attract a buyer for the utility, reports Philly.com. After attracting a buyer, UIL Holdings Corp. (ticker: UIL) of New Haven, Connecticut, Nutter had hoped to sell PGW for $1.86 billion in a deal that would get Philadelphia out of the energy business and bolster its struggling pension fund.

Not everyone is satisfied with this deal, however. Philadelphia City Council President Darrell L. Clarke announced that the Council would not consider the UIL sale, according to a separate Philly.com report. Opponents of the sale say Mayor Nutter did not consider alternatives before he launched the formal sale process in 2013. The UIL agreement to purchase PGW was announced in March 2014.

Concentric Energy Advisors was commissioned to conduct a study of the city’s best options regarding PGW. Concentric’s report is entitled Philadelphia Gas Works Highest and Best Use Study. The report was presented to the Philadelphia City Council in Oct. 2014.

One of the alternatives is expanding PGW’s LNG plant to produce more liquefied natural gas. PGW already owns a LNG plant on Port Richmond Waterfront that is operating under capacity, and could be used to satisfy a lucrative market if expansion of its liquefaction capacity is undertaken.

The Concentric report said that PGW could more than double its profits from off-system LNG sales to $7.7 million to $10 million a year, recovering the cost of a LNG liquefaction plant expansion in four to eight years.

In its report, which explored several ways to increase PGW’s revenue and reduce costs, Concentric said PGW could achieve the biggest saving – up to $17 million a year – by buying natural gas from the Marcellus Shale region rather than from Gulf Coast producers. Concentric said that it viewed “a dramatic expansion to serve LNG export markets as unrealistic and non-viable under any PGW partnership or ownership structure.”

Concentric said “PGW is too late to the competition” to export LNG from Philadelphia, but that expanding their operation would more closely conjoin the utility to a growing private-sector movement to build up the region as the Marcellus Shale energy hub.

Other options in the Concentric report included PGW supporting the creation of a regional natural gas vehicle (NGV) market.

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

November 13, 2014 - 5:03 pm Oil and Gas 360 Articles
Two Natural Gas End User Solutions Move Ahead in Pennsylvania, Texas

Two Natural Gas End User Solutions Move Ahead in Pennsylvania, Texas

Innovation:  small electric generators will use bottled up Marcellus gas for distributed electricity; small scale GTL plant for Houston gets greenlight to turn natural gas and ethane into transportation fuel

Pennsylvania’s IMG Midstream L.L.C. plans to supply the Marcellus shale region with at least a dozen 20 megawatt (MW) electrical generation stations to support regional production. The stations are intended to be placed close to the fuel source—the gas wells themselves— and circumvent the need to wait for further pipeline build, a problem that has road-blocked delivery of gas to end users in the Marcellus region during its unprecedented production growth the past decade.

Where a commercial scale 1100 megawatt (MW) power generation plant creates enough electricity to serve about 700,000 average homes, or approximately 2,000,000 people, the IMG plants are scaled to serve the local populous, about 26,000 homes.

Last week IMG presented plans to the Northern Tier Regional Planning and Development Commission in Wellsboro, Pa. to build nine 20-megawatt power stations in Bradford, Tioga, Susquehanna and Wyoming Counties.

The company’s business model is to site the plants close to natural-gas production and electric grids, minimizing the need for new infrastructure, a company spokesperson told the Philadelphia Inquirer.

IMG is targeting gas producers with a long-term market alternative which could help to improve netback pricing and deliver a local alternative for the monetization of gas, NGLs or processed ethane from producers throughout the Appalachian Basin.

IMG’s facilities are capable of utilizing fuel with Btu content exceeding 1,600 LHV (Btu/cubic foot).  Fuel supply to these facilities is flexible over time, which presents an opportunity for suppliers to deliver fuel supply to IMG based on wider market conditions for NGLs and/or natural gas.  By utilizing existing electrical grid infrastructure, IMG’s facilities can be sited to maximize the benefit of this fuel flexibility for participating suppliers. The price paid to producers per dekatherm (Dth) can be fixed, indexed to gas, indexed to power, based on an NGL price, or structured as a composite of select commodities and/or plant performance.

Each facility consumes approximately 4,000 Dth/day. Facilities are sized and located based on the availability and quality of fuel supply, electric infrastructure and market prices for electricity. One or multiple facilities can be constructed on a single gas gathering system and the plants are designed with a 20-year lifespan.

General Electric’s distributed power division will supply 10 Jenbacher J-624 two-stage turbocharged gas engines to IMG for two 20 MW projects, GE announced in August. Each of the Jenbacher units will deliver 4.3 MW of power. The initial two projects in Northeastern Pennsylvania are expected begin in 2015 and GE said there are 12 additional projects in development.

IMG is backed by Bregal Energy, a New York private equity investor with an array of energy investments involving power generation, exploration and production, transmission and renewable energy projects.

Houston Small Scale Gas-to-Liquids Facility Gets Green Light

California’s Greyrock Energy has received a final investment decision to deliver one of the world’s first small-scale Gas-to-Liquids (GTL) facilities near Houston.

The idea is to produce premium synthetic diesel fuel from natural gas or natural gas liquids (NGLs) using Greyrock’s GreyCat™ catalyst and Distributed GTL (dGTL) solution. Modular gas conversion can be achieved from a variety of abundant gas sources, including natural gas, NGLs (such as ethane), stranded gas resources and associated gas. Greyrock expects the Houston plant to be commercially operational by the end of 2015.

The project is being funded by a consortium of investors led by Dallas-based Sterling Private Capital and Eagle Oil & Gas Co.

“In addition to conversion of natural gas into fuels, we are very excited about the opportunity to convert NGLs, especially ethane, in geographies where ethane pricing is depressed and a challenge for producers to deal with,” said Pat S. Bolin, chairman of Eagle Oil & Gas Co., in a press release.

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

November 5, 2014 - 5:16 pm Midstream, Oil and Gas 360 Articles, Oilfield Services
Cabot Oil & Gas Affirms 2015 Growth despite “Challenging” Market

Cabot Oil & Gas Affirms 2015 Growth despite “Challenging” Market

A natural gas market with intense competition and possible oversupply will not deter Cabot Oil & Gas (ticker: COG) from increasing production volumes by 20% to 30% in 2015, the company said on Friday. Cabot, the second largest producer in the Marcellus Shale, increased production by 3.7% on a quarter-over-quarter basis in its Q3’14 earnings release. The volume is a 24% spike compared to volumes from Q3’13.

Cabot versus a Difficult Market

“Even during a period when we experienced lower natural gas price realizations and some unplanned production downtime, we were still able to provide top tier growth in production and cash flows while generating top tier returns, which is a testament to the quality of our assets and our operations,” said Dan Dinges, Chairman, President and Chief Executive Officer of Cabot in a conference call following the release.

The company removed one rig from its Marcellus region and the future rate of development will depend largely on market conditions, management said. Nine rigs are currently in operation, with five in the Marcellus and four in the Eagle Ford.

Despite the recent bear market, COG said the company is still realizing 50% returns with oil prices at $80. On a base case of $2.80/Mcf and $88/barrel, typical returns in the Marcellus and Eagle Ford are 80% and 60%, respectively.

Pipeline Access on the Way

Management expressed excitement regarding the approval of Constitution pipeline – news that reached the wire just hours before Cabot’s conference call. Now that the Federal Energy Regulatory Commission has green-lighted the project, COG believes construction could start as early as Q1’15 with the pipeline becoming operational as early as the end of 2015.

“We believe we are going to get 0.5 Bcf of our gas to a different price point, and that price point has historically been better than the general market,” said Dinges.

The addition of Constitution is the most impactful near-term inflection point for Cabot, but even more projects are on the way. “There are numerous projects that affect us both directly and indirectly and will certainly expand takeaway during 2015, 2016 and 2017,” said Jeffrey Hutton, Senior Vice President of Marketing. The Rose Run and Columbia East Side pipelines were singled out as future contributors, and the Leidy Southeast line was defined as a project of particular importance to Cabot. The Atlantic Sunrise pipeline, expected by 2017, will provide $850,000 in daily takeaway capacity.

“All in all, it’s shaping up,” said Hutton. “We’re thrilled about Constitution’s step forward, but there will always be additional capacity on the horizon.”

Eagle Ford Update

Cabot’s main focus area has always been the Marcellus, but the company is dialing up its presence in the Eagle Ford. COG acquired 30,000 acres in September to bolster its Buckhorn area, which now consists of 60,000 acres. The first Buckhorn well is expected to be placed online before the end of the fiscal year.

Ten wells outside of the Buckhorn area were placed online in the quarter, returning an average 30-day production rate of 751 BOEPD (91% oil). The company is actively testing 300-foot downspaced wells and two pilots returned a cumulative total of 230 MBOPD in the first six months of production. If the full downspacing test is successful, the company believes its drilling inventory will exceed 1,000 locations.

Q3’14 Eagle Ford production was 10.3 MBOPD. The company does not plan on restricting production any time soon, saying spot prices would have to fall below $70 in order to consider adjusting the program.

The Eagle Ford is expected to receive 46% of Cabot’s 2015 capital budget, which is slated at $1.53 billion to $1.60 billion. The Marcellus will command 52% of the budget. Overall, Cabot expects to drill 180 to 190 net wells in 2015 (80 to 85 in the Eagle Ford).

“The addition of this high margin production should help us offset some of the lost margins we are seeing from our natural gas sales in the current price environment,” concluded Dinges.

[sam id=”3″ codes=”true”]

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

October 24, 2014 - 6:58 pm Earnings, Oil and Gas 360 Articles
What does Chesapeake’s $5.4 billion Marcellus Divesture mean for Magnum Hunter Resources?

What does Chesapeake’s $5.4 billion Marcellus Divesture mean for Magnum Hunter Resources?

Despite the weight the Marcellus/Utica region carries on the oil and gas industry, E&Ps continue to de-risk and explore parts of the play in an attempt to find the elusive “sweet spot.”

Chesapeake Energy (ticker: CHK), one of the play’s pioneer companies, sold its southern Marcellus acreage last week to Southwestern Energy (ticker: SWN) for a price tag of $5.4 billion. Industry analysts widely agreed SWN paid a hefty sum for the properties, as OAG360 covered in a feature article following the announcement. The larger than realized price is an indication of regional popularity moving to the south, which has been aided by the emergence of the Utica Shale. Sell side analysts placed per-acre values in the transaction at anywhere from $8,000 to $9,625.

Southern Stronghold: Magnum Hunter Resources

Positioned on the south side of the play is Magnum Hunter Resources (ticker: MHR). Gary Evans, Chairman and Chief Executive Officer of MHR, has often referred to the company’s position as “unique,” and its early entry into the area allowed MHR to build out infrastructure and secure takeaway capacity. MHR had a banner month of September, setting a record in takeaway capacity through Eureka Hunter, its pipeline subsidiary, and drilling a record Utica well in Tyler County, West Virginia. The Stewart Winland 1300U’s initial production rate reached 46.5 MMcf/d, and is not only the first Utica well to be drilled in West Virginia, but is the southernmost Utica well drilled to date.

Valuation Perspective

Sell side analysts from numerous security groups viewed the CHK sale as a positive for MHR, due to the acreage value. SunTrust Robinson Humphrey said the value per acre was nearly double the price of prior sales. Capital One Securities said, “We value MHR’s acreage in the area at ~$14K/acre, but the stock is not pricing in that level.”

Gabriele Sorbara of Topeka Capital Markets described MHR’s acreage as “superior” in a note on October 16, 2014. “Based on our calculation, the assets were acquired for $13,015 per flowing Mcfe/d and $8,947 per acre (adjust for acquired production),” the note says. “An average of these transaction metrics on Magnum Hunter’s production and acreage implies upside of 39.2%… By early next year, we believe management will have transitioned to a pure-play Appalachia company with an improved balance sheet/capitalization and greater transparency on its Utica potential. Further, with its scale in the core Marcellus/Utica shale, we believe Magnum Hunter makes for an attractive takeout over the next 12 months.”

Indeed, MHR does plan on transitioning to a pure-play Appalachia company. Evans told OAG360 in an exclusive interview that Magnum Hunter could potentially divest all of its Bakken assets by the end of the year, bringing in an additional $400 million of asset sales at its midpoint. More than $200 million in the area has already been sold to date. “That will completely change up our balance sheet and we think that’s the right move at this time in our life cycle,” said Evans.

MHR announced production rates of 19 MBOEPD in August, but has not provided an pro forma update with any of its new wells. The current production rate, in relation to enterprise value of $2,352 million, yields a rate of $123,789/flowing BOEPD. If production hits the forecasted year-end 2014 volume of 32.5 MBOEPD, multiples imply the company’s value would increase to $4,023 million (not accounting for increase in debt).

MHR Operational Update

Magnum Hunter Resources further proved the value of its acreage in a news release on October 22, 2014. The Stewart Winland 1300U was completed as a four-well pad, with the other three wells targeting the Marcellus. The Marcellus wells ranged in depth from 6,147 feet to 6,155 feet, received 27 to 29 hydraulic fracture stages and included horizontal laterals ranging from 5,676 feet to 5,762 feet. The wells tested at peak rates ranging from 16.8 to 17.1 MMcfe/d on adjustable chokes.

Total results from the Stewart Winland pad combined for a flow of 97.4 MMcfe/d, the company’s highest production test rates to date. Evans said the results are a “testimony to the quality of the rock underlying the company’s lease acreage.” Evans told OAG360 that he believes MHR’s acreage is in the core of the Marcellus/Utica and the rates of return are two to three times greater than the company’s returns in the Bakken.

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Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. A member of EnerCom, Inc. has a long-only position in Magnum Hunter.

October 22, 2014 - 5:27 pm Oil and Gas 360 Articles
How One Man’s Decision Cracked Open an Energy Revolution:  the Marcellus Shale Turns Ten

How One Man’s Decision Cracked Open an Energy Revolution:  the Marcellus Shale Turns Ten

The Marcellus shale represents almost 20% of U.S. natural gas production. Ten years ago it was zero.

Jeff Ventura is well aware of the oil and gas history associated with the state of Pennsylvania.

Titusville, 1859—Edwin Drake drilled the first commercially successful oil well to a depth of 69 feet. That well gave birth to the global petroleum industry. A hundred forty-five years later, lightning struck again in Pennsylvania. This time it was 150 miles south of Titusville, near Mt. Pleasant Township in October of 2004, when Ventura made a single decision.

Marcellus Shale Turns Ten - Oil & Gas 360

Jeff Ventura – Range Resources

With one year under his belt as Chief Operating Officer of Range Resources (ticker: RRC), Ventura was approached by a company geologist named Bill Zagorski who had returned from a visit to Texas’ Barnett shale, the birthplace of the shale revolution.

Zagorski said he had a ‘eureka moment’ after his visit with a colleague working in the Barnett. At the meeting he told his COO that he knew of a shale that he believed was much like the Barnett—the Marcellus shale in Pennsylvania. “The advantage being that the Marcellus covered a lot bigger area and came with a lot more upside,” as Ventura would later sum things up.

At the meeting, Zagorski proposed to Ventura that the company go back into an unsuccessful exploration wellbore that had sucked up millions of the company’s capital, thus far to no benefit. The bore, known as Renz #1, already had its surface area restored and was slated to be plugged and abandoned. Zagorski’s idea was to go back into the well and specifically target the Marcellus shale layer using a hydraulically fractured well completion.

“Bill presented the idea and he presented it very well,” Ventura said when retelling the tale to the American Association of Petroleum Geologists as the organization’s 2013 Halbouty lecturer.

“The conventional wisdom was: don’t test, it won’t work, it’s been tried before… . Decades of drilling through [the Marcellus] show that it’s water sensitive, it’s not going to work.” But Zagorski was positive about the prospect and had ample data to back up his idea, including documentation of numerous gas shows for the Renz #1 and other wells in the area. As Ventura later summed it up, “creativity with strong scientific basis topped conventional wisdom.”

After a lengthy discussion with the Range exploration team, Ventura approved Zagorski’s idea and told the Range team to “put a big, Barnett style water frac on it.”

That single business decision resulted in the discovery of what would become the largest producing natural gas field in the U.S., estimated to be the second largest on the planet, behind only the South Pars gas field in the Persian Gulf. The Marcellus shale boom was officially born.

“Looking back, it was one of the best decisions of my life,” Ventura, now CEO of Range, said.

marcellus shale

Source: EIA

How Big is the Marcellus?

No matter how you slice it, the Marcellus is big. The Marcellus and its cousin, the Utica shale, sprawl across the northeast U.S. and underlie approximately 80% of Pennsylvania, almost all of West Virginia, more than half of New York, and about half of Ohio.

Some estimates say the Marcellus might hold as much as 500 trillion cubic feet (Tcf) of recoverable natural gas. For framework purposes, U.S. natural gas domestic consumption hit a peak when the country used 3.2 Tcf of natural gas in January of 2012. If the 500 Tcf prediction is accurate, the Marcellus by itself could produce enough recoverable natural gas to supply 13 years of demand at January 2012 consumption levels. To put it in further perspective, the EIA reports U.S. gas withdrawals were just above 2 Tcf for the month of October 2004 when the Renz #1 discovery well kicked off Marcellus development. U.S. withdrawals were 2.65 Tcf for July 2014.

“Five years ago, the Marcellus produced barely 2 Bcf of gas per day. Now it pumps 16 Bcf/day, a fifth of America’s gas. It is at the heart of the U.S. shale gas revolution…,” Reuters recently reported. “The Henry Hub in southern Louisiana, which connects to more than a dozen on- and offshore pipelines from Texas and the Gulf of Mexico, has been surpassed as the most active place for trading physical U.S. natural gas by hubs in shale-rich Pennsylvania.”

Ventura’s decision to put a million-gallon frac on the Renz #1 and other Marcellus discovery wells opened up the floodgates to a tidal wave of drilling activity in Pennsylvania and West Virginia.

The result? For the past decade the Marcellus has boosted the country’s essential natural gas supplies and fueled low-carbon electricity and heat for U.S. families and businesses, led to the creation and/or support of more than 240,000 jobs in Pennsylvania alone, and delivered the foundation required to revive U.S. manufacturing—cheap, reliable energy.

Range Looking to Triple Production

Range Resources has reestablished itself on the back of the Marcellus. The company today has approximately one million net acres in Pennsylvania that are prospective for shale, including the Upper Devonian, Utica/Point Pleasant and the Marcellus. The stacked pay potential places the company’s acreage closer to 1.9 million net acres with potential for natural gas production.

In its Q2’14 earnings release published at the end of July, Range reported record-high production volumes averaging 1,105 MMcfe/d, a 21% increase over the prior-year quarter. Its quarterly net income increased 19% to $171 million. The company also increased future firm transportation capacity by 400,000 MMBtu/d and signed two LNG supply agreements.

Over the past four years, the company has moved 6.4 Tcfe of resource potential into proved reserves. Range says in its October 3 investor presentation that it has all the parts in place—the identified wells, planned infrastructure and contracted takeaway capacity—to profitably grow production to 3 Bcfe/d and it believes it can be cash flow positive in 2016, assuming current strip pricing.

Large Marcellus producers like Range Resources, Antero Resources (ticker: AR), Cabot Oil & Gas (ticker: COG), Chesapeake Energy (ticker: CHK), EQT Corporation (ticker: EQT), Chevron (ticker: CVX) and Anadarko Petroleum (ticker: APC) are betting on U.S. natural gas demand growth from sources beyond domestic heating and cooling demand.  Expectations for demand growth include global LNG exports, rising petrochemical demand, increasing numbers of new natural gas-fired power plants replacing carbon-intensive coal-fired generation, continued growth in U.S. manufacturing and a growing use of natural gas as transportation fuel.

The Marcellus Effect:  Welcoming Industry Back to the Rust Belt

France’s Vallourec (ticker: VK) recently completed a million-square-foot plant in Youngstown, Ohio, that will make steel pipe for the energy industry. It’s “the first mill of its kind to open here in 50 years,” the New York Times reported. “The facility, which cost $1.1 billion to build, will be joined next year by a smaller $80 million Vallourec plant making pipe connectors. … Here in Ohio, in an arc stretching south from Youngstown past Canton and into the rural parts of the state where much of the natural gas is being drawn from shale deep underground, entire sectors like manufacturing, hotels, real estate and even law are being reshaped. A series of recent economic indicators, including factory hiring, shows momentum building nationally in the manufacturing sector,” the Times reported.

Global Customers:  Preparing to Send U.S. Gas to Europe and Asia

The boost from the Marcellus gas production has helped shape the U.S.A. into a muscular energy player on a global scale, having an effect on world commodity prices and geopolitical decisions. The EIA’s International Energy Statistics report compares gas producing countries’ output through 2012. For 2012, U.S. natural gas production was 29.5 Tcf, the entire Middle East was 25.4 Tcf, and Russia was 23.1 Tcf. No other country or region comes close.

The Marcellus Shale Turns Ten - Oil & Gas 360

Drilling in the Marcellus

The Marcellus’s natural gas could bring energy stability to Europe and Japan over the next decade, when U.S. LNG export volumes are expected to kick into high gear as about a dozen proposed U.S. LNG export plants are planned to come online. On Oct. 8, 2014, Texas Gov. Rick Perry called for unlimited natural gas and oil exports, saying it would help the American economy and aid American allies threatened by Russia’s control of European natural gas supplies, the AP reported.

“The first order of business to restore balance in Europe is for America to build an energy shield to protect our strategic allies,” Gov. Perry said at Mississippi Gov. Phil Bryant’s Energy Summit. “That means we must accelerate our exports of America’s vast energy resources.”

The International Monetary Fund recently discussed the global implications of the U.S. shale boom. “In 2000, shale gas accounted for merely 1% of U.S. natural gas production. Today, shale gas production now accounts for about half of the total U.S. natural gas production, according to the IMF,” in a MarketWatch report. “The U.S. shale revolution … has been able to help stabilize international energy prices. With the disruptions seen in the geopolitical landscape, the increase in shale gas production has helped offset shortages, keeping prices lower than they would have been otherwise.

“The IMF reports that the shale revolution has given the U.S. an advantage in the natural gas arena, allowing it to be more competitive in non-energy products,” the report said.

“The Marcellus shale has fundamentally altered the outlook for the U.S. natural gas industry. The U.S. is emerging as a low-cost chemicals producer and is poised to become an exporter of natural gas—a feat unthinkable just 5 years ago when it was widely believed that increasing LNG imports would be needed to meet domestic demand,” the Oil & Gas Journal reported.

“The Best is Yet to Come”

It’s been 10 years since the Range team deliberated whether they should even test the Marcellus. The go-ahead decision from the company’s COO led to a world class natural gas basin that has accelerated the shale revolution and turned the U.S. into the world energy leader.

So what’s next for Range Resources and the Marcellus? Oil and Gas 360® asked that question today to Matt Pitzarella, Range’s director of communications and public affairs.

“Despite being the largest producing natural gas field in the United States, the best is still yet to come from the Marcellus and Range,” Pitzarella said. “We have the ability to grow 20-25 percent for many years on our way to tripling current production to 3 Bcfe/d net, driven largely by the Marcellus.”

What’s next for the Marcellus?

If Range succeeds in tripling its current production, Pitzarella sees these probable effects: “continued job creation, tax revenues for state and local governments, royalties for landowners, and possibly a new manufacturing renaissance for the Marcellus region.”

Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

October 17, 2014 - 5:09 pm Oil and Gas 360 Articles
Magnum Hunter Resources Achieves Record Well in the Utica: 46.5 MMcf

Magnum Hunter Resources Achieves Record Well in the Utica: 46.5 MMcf

Takeaway Record for Eureka Hunter Follows

Magnum Hunter Resources (ticker: MHR) is betting big in the Marcellus/Utica, and a company announcement on September 24, 2014, supports its assessment. The Stewart Winland 1300U well in Tyler County, West Virginia, returned an initial production rate of 46.5 MMcf after being drilled to a true vertical depth of 10,825 feet (including a 5,289 foot horizontal lateral) and fraced with 22 stages.

Oil plays are among the hottest acreage spots right now, as evidenced by Encana’s (ticker: ECA) $7.1 billion acquisition of Permian-focused Athlon (ticker: ATHL), announced on September 29, 2014. Magnum Hunter has gone a different route, selling off its assets in Canada and a portion of the Bakken within the last year to narrow its focus on the Appalachian. Management expects the company to be a pure-play Marcellus/Utica company in the near future.

Did the Utica just get Bigger?

The Stewart Winland 1300U accomplished three milestones:

  1. The timing of the IP was not disclosed, but MHR believes it is the highest rate for any Utica/Marcellus well to date. Rice Energy (ticker: RICE) drilled a well earlier in the year that tested at 41.7 MMcf over a 24 hour period.
  2. It is the first Utica well to be drilled in West Virginia. Chevron (ticker: CVX) is completing the only other Utica well and management said it expects to release results within the fiscal year.
  3. It is the southernmost Utica well drilled to date. MHR has built up its acreage in the southern region, which has returned greater rates than wells to the north.

“[The 1300U] is one of the highest flow rate gas wells ever reported in any shale play located in the U.S.,” said Gary Evans, Chairman and Chief Executive Officer of Magnum Hunter, in the company release.

“The initial shut-in casing pressure of this monster well was 9,050 psi. Even at a gas flow rate of 46.5 MMCF and choke size of 32/64 inches, flowing casing pressure was maintained at 7,810 psi. We look forward to further extending this play to the south with our existing lease acreage position.”

Management had previously told investors at EnerCom’s The Oil and Gas Conference® 19 about the high pressure involved with Utica wells due to its organic content. “It’s not really a shale, it’s more of a carbonate reservoir,” Evans said. “It’s got porosity, permeability and resistivity – all the things you look for. I think this play will turn out to be one of the largest gas fields in the world, and it’s already being compared to some of the fields in Saudi Arabia.”

Midstream Takeaway Sets Company Record

Pipeline access can be difficult in the Marcellus/Utica, where gas output has increased by more than 700% since 2010. Magnum Hunter’s entry into the southern Appalachia was conjoined by the purchase and construction of pipeline systems. Today, MHR has direct takeaway ability through Eureka Hunter, its midstream subsidiary consisting of 105 miles of pipe and 1.5 Bcf/d of capacity.

Eureka Hunter announced a company takeaway record of 316,500 MMBtu/d one day after MHR released results from the Stewart Winland 1300U. The company expects to set more records soon –construction crews will expand the network to 170 miles by year-end 2014, while takeaway is expected to reach 400,000 MMBtu/d. MHR expects the network to exceed the 200-mile mark by 2015.

The midstream access is an invaluable asset to bring down costs, says Evans. “Even today with sub-$4 gas price, you’re talking 60% to 70% IRRs,” he explains.

What’s next for Magnum Hunter Resources?

Magnum Hunter is one of the few companies exploiting both the Marcellus and Utica shales from single pads. Even the record-setting Stewart Winland 1300 pad is in the process of drilling and completing three Marcellus wells with true vertical depth of roughly 6,150 feet (average lateral length of 5,733 feet) and between 27 to 29 frac stages.

The company holds more than 200,000 net acres in the region, and believes roughly 43,000 net acres overlap the Marcellus/Utica. “The economics of pad drilling with two very distinct plays going on is quite unique and also has lots of challenges with respect to how you lay dual pipelines and how you complete these wells,” said Evans. “But, it’s very exciting and an area that we think is quite unique and it’s going to have some tremendous returns.”

Production is expected to ramp up considerably, with a 2014 year-end target of 32.5 BOEPD. That’s more than double Q2’14’s production of 15.9 BOEPD. Management is confident in reaching the goal due to incoming production from its new wells, which include operations on a total of four pads in the Marcellus/Utica. The forecasted rise in production has allowed management to publicly declare plans to take Eureka Hunter public in 2015 as a Master Limited Partnership.

MHR Has roughly 50 wells drilled to date in the Appalachia but believe it holds more than 1,400 gross drilling locations with 64.1 MMBOE of proved reserves. Moving forward, the company believes it can expand its knowledge of the Marcellus into the Utica formation. “We think we have the Marcellus code down,” said Evans, noting well costs average $6.5 million apiece with up to 12 Bcfe of returns. “And, we know for a fact we are in a very good place.”

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Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. A member of EnerCom, Inc. has a long-only position in Magnum Hunter Resources.

September 29, 2014 - 5:21 pm Midstream, Oil and Gas 360 Articles

Shell Divests Pinedale and Haynesville, Adds 155,000 Net Acres in the Marcellus and Utica

Royal Dutch Shell (ticker: RDS.A) is shifting around its U.S. onshore assets.

Yesterday, the company announced it will acquire 155,000 net acres in the Pennsylvania Marcellus and Utica from Ultra Petroleum (ticker: UPL). Ultra agreed to pay Shell $925 million for 100% of Shell’s Pinedale asset in Wyoming.

In separate agreement, Shell has agreed to sell 100% of its Haynesville asset in Louisiana for $1.2 billion to Vine Oil & Gas LP and Blackstone.

“We continue to restructure and focus our North America shale oil and gas portfolio to deliver the most value in the longer term. With this announcement we are adding highly attractive exploration acreage, where we have impressive well results in the Utica, and divesting our more mature, Pinedale and Haynesville dry gas positions,” said Marvin Odum, Shell’s Upstream Americas Director in a company news release.

During the first half of 2014, Ultra’s net production from its divested Pennsylvania assets Shell averaged 109 MMcf/d (19 MBOEPD). The Shell net production from Pinedale in the second quarter 2014 was 190 MMcf/d of dry gas (32 MBOEPD).

Shell’s Pinedale asset (which includes 19,000 net acres of leasehold interest, 1,108 gross wells and associated facilities, and an average of 0.7 percent overriding royalty interest in 11,500 acres) will be exchanged for cash and Ultra’s 100 % interest in the Marshlands area (63,000 net acres) as well as its entire interest (92,000 net acres) in the Tioga Area of Mutual Interest (AMI), an unincorporated joint venture with Shell.  After completion of this transaction, Shell will have a 100 percent interest in the Tioga AMI.  The agreement is effective April 1, 2014, and is expected to close this year.

Shell’s Haynesville asset includes 107,000 net acres in in north Louisiana.  The transaction includes 418 producing wells, 193 of them operated by Shell. As of 1 July 2014, the gross production from the Haynesville asset was approximately 700 MMcf/d of dry gas, with Shell’s net working interest share at approximately 250 MMcf/d (43 MBOEPD).  The agreement is effective July 1, 2014, and is expected to close in Q4’14.

The sales are part of Shell’s larger plan to shed $15 billion in assets around the world, according to PetroGlobal News.

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Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. A member of EnerCom, Inc. has a long only position in Shell.

Marcellus Gas Output Tops 15 Bcf/Day in July

Marcellus Gas Output Tops 15 Bcf/Day in July

Experts were predicting half way through 2013 that what was unthinkable just a year before might actually happen in 2013: the Marcellus gas production might reach 10 Bcf/day.

The shale deposit that now accounts for almost 40% of U.S. shale gas production blew past that milestone and it has now achieved another milestone:  natural gas production in the Marcellus region surpassed 15 billion cubic feet per day (Bcf/d) through July, according to the EIA’s newest Drilling Productivity Report. The Marcellus shale production climbed to today’s level from 2 Bcf/d in 2010.

The EIA says six shale plays accounted for 95% of domestic oil production growth and all domestic natural gas production growth during 2011-13.

Pages from 08052014 Marcellus Output Tips 15 Bcf

The EIA reported for July that the rig count in the Marcellus Region has remained steady at around 100 rigs for the past 10 months. “Given the continued improvement in drilling productivity, which EIA measures as new-well production per rig, EIA expects natural gas production in the Marcellus Region to continue to grow. With 100 rigs in operation and with each rig supporting more than 6 million cubic feet per day in new-well production each month, new Marcellus Region wells coming online in August are expected to deliver over 600 million cubic feet per day (MMcf/d) of additional production. This production from new wells is more than enough to offset the anticipated drop in production that results from existing well decline rates, increasing the production rate by 247 MMcf/d,” the EIA said.

Marcellus Pioneer Not Slowing Down

One company that has led the development of the Marcellus Shale is Range Resources (ticker: RRC). Range’s aggressive development timeline in the Marcellus illustrates how it and fellow independent oil and gas companies created the U.S. Shale Boom:


 

2004:  Range initiates Marcellus development, drilling the Renz #1 in Washington County, PA.

2006-2007:  Within 18 months, Range entered five shale plays, growing shale gas production from zero to 60 Mmcfe/day.  Net acreage prospective for shale gas development grew from 180,000 to 650,000 net acres.

2008:  The Company’s net acreage in the Marcellus Shale grew to more than 900,000+ acres.  The Company brought in Mark West Energy Partners, L.P., to construct processing and gathering facilities and exited the year with net production from the Marcellus of 30 Mmcfe/day.

2009:  Range drilled 55 horizontal shale wells in the Marcellus shale driving net production past the 100 Mmcfe/day milestone before year-end.  Range drilled its first two horizontal wells in the northeastern core of the Marcellus both with seven-day production rates above 13 Mmcfe/day. Bill Zagorski, VP of Geology is recognized as the “Father of the Marcellus” by the Pittsburgh Association of Petroleum Geologists.

2010:  Range completed its first Upper Devonian and Utica test wells with favorable results.  In the Marcellus shale, the company drilled more than 100 horizontal wells and exited the year with net production in excess of 200 Mmcfe/day.

2011:  Range sold its North Texas Barnett Shale acreage and production for approximately $900 million and funded increased activity in the Marcellus.  The Company exited the year with net production of over 400 Mmcfe/day from the Marcellus.

2013:  Range’s corporate net production volumes surpassed 1 Bcfe per day; Marcellus gross production reaches 1 Bcfe per day.

2014:  Range’s total proved reserves reached 8.2 Tcfe, as well as resource potential reaching 64 – 85 Tcfe. In the Marcellus, Range reports 41 – 51 Tcfe resource potential with its approximately 1 million net acres.

SOURCE:  Range Resources


 

In its Q1’14 earnings release, Range President and CEO Jeff Ventura said Range had the ability to grow its net production to 3 Bcfe/day, or three times its current production. “The wells have been identified, the compression and plants have been scheduled, and the takeaway capacity to multiple markets has been secured.”

Range has earmarked 87% of its $1.52 billion capital budget to continue its Marcellus drilling and development program.

On its Q2’14 earnings call, Jeff Ventura, Range President and CEO, said: “For the second half of 2014, we plan to drill Marcellus wells that are projected to have an average lateral length of 5,413 feet, some with laterals over 10,000 feet. On our first quarter conference call in April, it was great to announce that Range has just drilled what we believe is the highest-rate Marcellus well ever drilled by any company in the southwest portion of the play. That well had an initial 24-hour rate of 38.1 million equivalent per day. This well had its 7,065-foot lateral completed with 36 stages. And it’s located in Washington County, Pennsylvania.”

“This quarter, I’m excited to announce that we drilled and completed our best well ever on our Northeast acreage position. This well had an initial rate of 28 million per day from a 6,553-foot lateral with 33 stages. It could’ve IP’d for a much higher rate but was constrained by our surface facilities. This well set a new 30-day production record for Range and averaged 25 million per day for this period. This well has been online now for 40 days and is still producing 22 million per day. The cost to drill and complete this well was $5.2 million. We have multiple potential offsets to the well.”

Range says its ethane contracts have cleared a path, allowing overall capacity to reach 3 Bcfe per day net from the Marcellus alone. “We are projecting that we could be able to move 4 to5 Bcf per day of Appalachian gas to where two-thirds of the current United States demand for natural gas exists,” the company said in its 2013 annual report to shareholders. In addition, Range foresees selling its natural gas liquids to export markets in Europe, South America and Asia as export and import facilities come online.

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Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

A Tale of Two Shale States: When Will New York Drill the Marcellus?

A Tale of Two Shale States: When Will New York Drill the Marcellus?

Almost half of the state of New York is underlain by the Marcellus shale, the nation’s most prolific natural gas deposit. But thanks to a long running delay in permitting—to study hydraulic fracturing—ever since 2008, the State of New York has dragged its feet on shale development. In doing so it has kept landowners, citizens, municipalities and itself from benefiting from the shale boom, which requires fracturing shale to release the gas for production.

Then there’s Pennsylvania. As far as shale production goes, Pennsylvania and New York are like two brothers with opposite inertia. The one brother is motivated to get after it, while the other brother does a lot of nothing. Since 2007, New York has been dragging its feet when it comes to allowing companies to drill the Marcellus. In the same time period, Pennsylvania’s landowners, business community and citizens have reaped the benefits of drilling the Marcellus shale in a big way.

The Fruits of Pennsylvania’s Labor

While its brother New York has sat idle since 2007/8, Pennsylvania has drilled gas wells. Pennsylvania produced and sold 86 times more natural gas than New York in 2012, according to the EIA. Currently, New York has roughly 7,000 gas wells in production. Pennsylvania has more than 55,000 – second only to Texas.

The accompanying chart tells the story. The gold line that rockets straight up the right side of the chart, beginning in 2008, represents Pennsylvania’s natural gas marketed production through 2012, according to the EIA. The flat blue horizontal line lying on the bottom of the chart represents New York’s natural gas marketed production for the same period.

New York’s production shrank to 26.4 Bcf in 2012 from 54.9 Bcf in 2007, while its brother Pennsylvania had a major growth spurt during the period. Natural gas produced and sold by the state of Pennsylvania grew to 2,260 Bcf in 2012 from 182 Bcf in 2007. Such is the effect the shale boom.

Source: EIA

Source: EIA

A 2011 report entitled The Economic Opportunities of Shale Energy Development, authored by University of Wyoming professor Timothy Considine for the Manhattan Institute, stated the following regarding New York’s moratorium on drilling in the Marcellus:

“What ending the moratorium means for New York:

  • $11.4 billion in economic output and $1.4 billion in tax revenues;
  • $4 million in economic benefits from each well but only $14,000 in economic damages from environmental impacts;
  • Some 15,000 to 18,000 jobs could be created in the Southern Tier and Western New York, regions which lost a combined 48,000 payroll jobs between 2000 and 2010;
  • 75,000 to 90,000 jobs could be created if the area of exploration and drilling were expanded to include the Utica Shale and southeastern New York, including the New York City watershed.”

70,000 Marcellus Landowners Sue New York

New Yorkers have felt the pinch. New York began its review of hydraulic fracturing in 2008 after state lawmakers passed legislation to promote shale gas development in New York. Six years later, property and mineral rights owners along with oil and gas companies operating in Pennsylvania’s Marcellus shale are still waiting for the results.

Missing the shale boat prompted a group of 70,000 mineral owners in New York to file a lawsuit earlier this year against the governor and two state agencies for illegally prolonging the review process.

The Joint Landowners Coalition of New York Inc. demanded that the state complete their studies of the environmental and health effects of hydraulic fracturing. “The current delay of five and a half years is legally unjustifiable, the suit asserted,” according to an article by Law360 written at the time the suit was filed. “The group was joined in the suit by the Kark Family Trust, LADTM LLC and Schaefer Timber & Stone LLC, who all claim that the state’s delay has prevented them from benefiting from mineral rights on their land.”

“They are unable to sell, auction, lease or otherwise dispose of their mineral rights by reason of the negative reputation that is being created for New York state as a result of the protracted delays associated with the supplemental generic environmental impact statement process,” the complaint said.

Suit is Thrown Out

The lower court dismissed the suit on July 14, 2014, finding that the landowners did not have standing to sue Governor Cuomo, the environmental agency and the health department.

Landowners File Appeal

Joint Landowners Coalition of New York filed an appeal July 28, 2014, with the state Appellate Division of the New York Supreme Court, asking it to overturn the lower court decision.

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Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

July 30, 2014 - 5:56 pm Fracing, Oil and Gas 360 Articles
Marcellus/Utica Growth Continues for Rice Energy; Adds 22,000 Net Acres from Chesapeake

Marcellus/Utica Growth Continues for Rice Energy; Adds 22,000 Net Acres from Chesapeake

Rice Energy (ticker: RICE) is an independent natural gas and oil company engaged in the acquisition, exploration and development of hydrocarbons in the Appalachian Basin. The company filed its initial public offering in January 2014. Approximately 33% of the company’s shares are owned by management following the closing of $900 million in unsecured senior notes in April 2014. Proceeds from the offering are being used to de-risk Rice’s 2014 capital expenditures plan.

Rice announced the acquisition of approximately 22,000 net acres in the Marcellus region from Chesapeake Appalachia, LLC on July 7, 2014. Total acquisition price is $336 million and includes 12 developed Marcellus wells (seven currently producing) in western Green County, Pennsylvania, with total production of 20 MMcf/d. The transaction has an effective date of February 2, 2014 and is expected to close in August 2014. In the press release, Toby Rice, President and Chief Operating Officer, said: “The acquired assets provide us with a foothold to pursue additional leasehold opportunities and further grow our inventory of low-risk, high-return projects.”

The acreage addition increases Rice’s footprint by 24% in comparison to its Q1’14 totals on March 31, 2014, and increases its Marcellus net risked locations to 325 from 152 – a 47% rise. According to a note from Neal Dingmann of SunTrust Robinson Humphrey, the metrics of the deal are in line with recent deals in “highly developed” Marcellus areas and amount to $15,273/acre, or $11,485/acre assuming $4,167 per flowing Mcf.

In its Q1’14 earnings release, Rice listed $910.6 million in total debt and roughly $1.1 billion in total liquidity, with $704.4 million in cash on hand and $278.7 million available on its credit facility. The totals were all used to take into account the $110 million Momentum acquisition, which comprised of midstream and gathering assets in the Marcellus region. The company anticipates funding its latest purchase from borrowings, cash on hand and the possibility of equity capital markets.

Rice Energy – Upsizing

Rice is still on track to achieve its goal of adding 30,000 to 40,000 net leasehold acres within calendar 2014. Pro forma for its recent purchase, the company has roughly 112,000 net acres in the Marcellus/Utica and has a total of 57 producing wells. An additional 50 wells are currently in the process of completion.

Total production in regards to its Q1’14 numbers are now 229 MMcfe/d, and the company plans on reaching 260 MMcfe/d to 310 MMcfe/d by the end of 2014 – all of which is dry gas. The numbers would be respective increases of 157% and 220% (midpoint) compared to Q1’13’s total of 89 MMcfe/d. In its Q1’14 conference call on May 13, 2014, Rice management said its midstream team was ahead of schedule on infrastructure buildout in the region, which is a notable achievement due to historical capacity constraints in the region.  

Chesapeake – Right-sizing

Chesapeake Appalachia’s parent company, Chesapeake Energy Corporation (ticker: CHK), plans on selling $4 billion of its assets in 2014 and spun off its oil services company to its own entity, known as Seventy Seven Energy (ticker: SSE), on July 1, 2014. CHK divested an additional $4 billion in assets in 2013 as an ongoing effort to right-size the company. While the divestments sales are large, Chesapeake is attempting to keep its production stable. At an analyst day on May 17, 2014, Doug Lawler, Chairman and Chief Executive Officer of Chesapeake Energy, said: “You see a lot of companies out there that are increasing CapEx and increasing production. You see some that are increasing CapEx and decreasing production. Chesapeake is increasing production and maintaining flat CapEx. As we look at the current outlook today, the work has taken place in the Company to continue to improve our balance sheet.”

According to a company presentation on June 25, 2014, Chesapeake has reduced $6.2 billion of leverage since 2013 but anticipates a compounded annual growth rate (adjusted for divestures) of 7% to 10% through 2019.

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Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication.

Marcellus and Utica Outpacing Regional Infrastructure as Production Estimates Continue to Rise

Marcellus and Utica Outpacing Regional Infrastructure as Production Estimates Continue to Rise

Acute need:  6 new pipeline projects under construction + 19 awaiting approval could add 3.5 Bcf/d capacity in 2015

The United States natural gas boom, spearheaded by the expanded development of the Marcellus Shale, has boosted the country to become the world’s top natural gas producer. Reports from the EIA show production from the Marcellus has increased, on average, by 280 MMcfe/d by month since 2007. Below the prolific play lies another giant: the Utica Shale. The Utica, although deeper than the Marcellus, is believed to hold a resource base of 15.7 Tcfe of recoverable resources, according to the Energy Information Association’s (EIA) 2012 Annual Energy Outlook. The United States Geological Survey estimated the region holds as much as 38.2 Tcfe of recoverable gas and spans six states in the northeast.

Source: Bloomberg, Data Compiled by EnerCom

Source: Bloomberg, Data Compiled by EnerCom

ICF International (ticker: ICFI) projects total gas production in the region to reach 34 Bcf/d by 2035, according to its Q2’14 Detailed Production Report. The target number would represent an increase of 36% compared to projected production of 25 Bcf/d in the company’s Q1’14 report. ICF also increased the estimated ultimate recovery (EUR) of wells from both plays, with the Marcellus increasing to 6.2 Bcf from 5.2 Bcf (19% higher) and Utica wells to 3.3 Bcf from 2.5 Bcf (32% higher).

The Detailed Production Report projects the rise in EURs due to improvements in drilling technology. The new technology will lead to closer laterals and faster drilling times. In all, a total of 2,550 wells are expected to be completed in the region annually, including 2,050 in the Marcellus and 500 in the Utica. The report from the previous quarter estimated total 2,045 well completions, with the Marcellus and Utica accounting for 1,750 and 395 wells, respectively.

Capacity Increases Necessary

Increased production, however, must be equaled with increased takeaway capacity. The Marcellus has grown so rapidly that infrastructure has struggled to keep pace – the Algonquin pipeline to New England, for example, was operating near maximum capacity in 2012. The harsh winter wreaked havoc on gas pipelines, catapulting spot prices in the Northeast to more than 20 times the Henry Hub price. The constrained gas markets from winter have affected natural gas storage levels to this day, and are currently 31% below the five-year average. As of November 2013, six new pipeline projects were under construction and an additional 19 were in various stages of the approval process. The EIA expects the expansions to add 3.5 Bcf/d of capacity by 2015.

The Oil & Gas Journal reports that Greg Hopper, Vice President of ICF International, said the spread between oil and natural gas prices has made natural gas liquids (NGLs) more valuable than dry gas. The Marcellus and Utica have higher amounts of NGLs compared to more traditional gas plays like the Barnett and Haynesville. As a result, exploitation of the Marcellus/Utica continues to rise while production of other gas regions continues to fall.

The ethane and propane components of NGLs add to the infrastructure strain. Ethane, in particular, is being rejected due to transportation limitations and remains in the pipelines. Companies like Range Resources (ticker: RRC) are diversifying their market portfolio to increase sales. Range has developed a market based purely off of ethane and has contracts in place to distribute 75 MBOEPD of ethane production to three different LNG hubs across North America. Once operational, the pipelines will provide a 25% cost uplift as opposed to selling the gas as a BTU, said RRC management.

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Important disclosures: The information provided herein is believed to be reliable; however, EnerCom, Inc. makes no representation or warranty as to its completeness or accuracy. EnerCom’s conclusions are based upon information gathered from sources deemed to be reliable. This note is not intended as an offer or solicitation for the purchase or sale of any security or financial instrument of any company mentioned in this note. This note was prepared for general circulation and does not provide investment recommendations specific to individual investors. All readers of the note must make their own investment decisions based upon their specific investment objectives and financial situation utilizing their own financial advisors as they deem necessary. Investors should consider a company’s entire financial and operational structure in making any investment decisions. Past performance of any company discussed in this note should not be taken as an indication or guarantee of future results. EnerCom is a multi-disciplined management consulting services firm that regularly intends to seek business, or currently may be undertaking business, with companies covered on Oil & Gas 360®, and thereby seeks to receive compensation from these companies for its services. In addition, EnerCom, or its principals or employees, may have an economic interest in any of these companies. As a result, readers of EnerCom’s Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this note. The company or companies covered in this note did not review the note prior to publication. EnerCom, or its principals or employees, may have an economic interest in any of the companies covered in this report or on Oil & Gas 360®. As a result, readers of EnerCom’s reports or Oil & Gas 360® should be aware that the firm may have a conflict of interest that could affect the objectivity of this report.

June 27, 2014 - 5:13 pm Midstream, Oil and Gas 360 Articles