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NewsLetters

Expo/Industry events for the next few months

Utica Upstream
April 6, 2016
Pro Football Hall of Fame
Canton, OH

www.uticacapital.com

Upstream PA 2016
April 19, 2016
Penn Stater Inn
State College, PA

www.upstreampa.com

Ohio Valley Regional Oil & Gas Expo
April 26-27, 2016
Belmont County Carnes Center
St. Clairsville, OH

http://www.ohiovalleyoilgasexpo.com/

Latest facts and a rumor from the Marcellus and Utica Shale

  • Highlights from MUM.  Congrats to Hart Energy for another superb conference.  In spite of the downturn, Hart Energy brought together industry experts to keep everyone updated with the latest information from the industry’s major players.  

    We found the conference very worthwhile and left with a number of good contacts.  A number of other exhibitors commented similarly to me that while the numbers were down, the decision-makers were certainly at MUM.  With the downturn in the industry, the “hard core” oil and gas companies will continue to support industry expos, conference and seminars.  

    There were a number of rumors floating around the conference.  I think downturns possibly generate more rumors that when times are good.  Here’s what I heard:
     
    • There have been a number of Chesapeake rumors this week
      • Chesapeake is cleaning up its royalty issues to prepare for a sale.  No one thinks Chesapeake can get out from under all its debt.  (RUMOR)
      • On Thursday afternoon, January 28th in Bellaire, OH, I heard that Chesapeake was talking about building 14 well pads in Jefferson County, OH.  (RUMOR)
      • Takeaway in NE PA will be greater than production by the end of 2016. (RUMOR)
    • MarkWest will be opening the Ohio Central Railroad in Harrison County, OH.  (RUMOR)
    • Shell will not make a final announcement about its building the cracker plant in Beaver County, PA.  It will just keep moving forward with the work which is aggressive.  I’ve been told that companies are working six-days a week at the cracker plant site.  (RUMOR)
    • Boom times for natural gas will come back in 2017 and 2018.  This is a comment that I’ve heard the last six months.  There are two reasons for the pickup in drilling:  the shale wells will be close to the bottom the decline curve and there will be many more pipelines in place.  (RUMOR)
    • Awarding of bids is being delayed.  A number of companies said that RFP’s are coming out, but the bid is not being awarded because the E&P Company and/or midstream company is thinking about rebidding in the spring when prices may be lower.  (RUMOR)
       
  • Cabot in the Eagle Ford.  Although Cabot has decreased its capital budget for 2016, there are still plans for them to do some drilling the South Texas Eagle Ford trend in Frio and Atascosa Counties.

    Cabot is a two play company - the bulk of their revenue comes from natural gas (Marcellus Shale play) while the Eagle Ford makes up the oil asset part of their portfolio with about 19% of total revenue stream.

    Planned Eagle Ford Capex for 2016 is expected to be about $150 MM - a 52% decrease from their 2015 numbers. Only 10 new wells are slated to be drilled in 2016 - versus 50 in 2015.

    Like many other operators, Cabot has reduced their drilling time from spud to TD significantly with the norm now being 6-7 days. Assuming $2-2.5 MM per well, the actual drilling of new wells will only use up $20-$25 MM of the planned Capex total.

    The puzzling part of the Cabot 2016 Eagle Ford plan as stated in investor releases is where the bulk of their planned Capex will be spent. With only the aforementioned small part of the $150 MM allocated to drilling new wells, over $125 MM in Capex is left to handle completions and facilities.

    It is unknown how many cased uncompleted wells Cabot has in the Eagle Ford trend, but this simplistic analysis of their 2016 Capex plans points to over 20 wells that could be completed in the coming year.

    Cabot's widespread acreage position in the S Texas trend has room for hundreds of new Eagle Ford locations. But a large part of this acreage position is already HBP by producing / drilled wells while only a small portion of their position is either term acreage or in a continuous

    Plus, as is the case everywhere in the Eagle Ford, there is a lot of variability across the Cabot position with respect of reservoir quality and potential. Part of their position is in a heavier oil (less than 30 API) area that will most probably result in lower per well reserves and associated economics.

    It will be interesting to watch Cabot's activity in the Eagle Ford trend as the year progresses - and to see if they alter their approach if oil stays in the $30 range.
     
  • Eclipse Resources Takes 4th Qtr. Charge.  Eclipse Resources said last week it expects to record a fourth-quarter impairment charge of $750-$850 million on certain Ohio oil and gas properties, due primarily to the huge commodity-price decline.

    The estimated impairment charge remains subject to revision based upon further analysis and final review, the independent producer said.

    Eclipse added it doesn’t anticipate the expected impairment will result in a violation of any financial covenants associated with its senior secured revolving credit facility or senior unsecured bonds.

    In other Eclipse news, the State College, Pennsylvania-based company last Thursday began a private offer to exchange $550 million of outstanding 8.875% senior unsecured notes due in 2023, for the company’s new 9% senior secured second-lien notes due in 2023.

    The exchange offer expires on Feb. 18, unless extended by Eclipse, Kallanish Energy learns. The settlement date is Feb. 19.

    The second-lien notes will be initially secured by second-priority liens on substantially all of Eclipse’s and any subsidiary guarantors’ assets.

    The liens securing the second-lien notes and related subsidiary guarantees will be subordinated to the liens on assets securing the Eclipse’s revolving credit facility and certain hedging and bank product obligations.
     
  • Rover Pipeline Delayed Again.  FERC has delayed the Rover Pipeline report until October.
     
  • Good news for Marcellus and Utica Producers.  Natural gas spot market prices are narrowing between the benchmark Henry Hub and pricing points in and around the Marcellus and Utica shale plays as new pipeline projects have come online, the U.S. Energy Information Administration said Wednesday.

    “With limited infrastructure to deliver natural gas to consumers, the Marcellus region can quickly become oversupplied, causing prices within the Marcellus [especially Pennsylvania] to be discounted,” the EIA said.

    New infrastructure projects have come online to alleviate the disconnect between prices in producing and consuming areas around the country, Kallanish Energy understands.

    While prices in the Marcellus are still low, trading under $1.50 per million British thermal units (MMBtu), the gap between Marcellus region price points and Henry Hub has narrowed, Kallanish Energy finds.

    The price at Transcontinental Pipeline’s (Transco) Leidy Hub in central Pennsylvania averaged $0.93/per MMBtu below the Henry Hub price from Dec. 1, through Jan. 15. However, last July, the differential was much larger, averaging $1.65/MMBtu for the month, EIA found.
     
  • Antero 2015 Reserves Announcement Highlights:
     
    • Proved reserves increased by 4% to 13.2 Tcfe at year-end 2015
    • Proved developed reserves increased by 54% to 5.8 Tcfe at year-end 2015
    • All-in finding and development cost for proved reserve additions from all sources was $0.80 per Mcfe for 2015
    • All-in 3-year finding and development cost for proved reserve additions from all sources through 2015 was $0.57 per Mcfe
    • Proved undeveloped reserves at year-end 2015 have estimated future development cost of $0.69 per Mcfe
    • Pre-tax PV-10 of 3P reserves at year-end 2015 was $6.8 billion at SEC pricing including hedges
    • Pre-tax PV-10 of 3P reserves at year-end 2015 was $13.7 billion at 12/31/2015 strip pricing including hedges
       
  • 10 Takeaways From Schlumberger's 4th Qtr. Conference Call (Thank you, Oilpro):
  1. Schlumberger CEO Sees His Customers Experiencing A Financial Crisis. In the press release, Paal Kibsgaard used strong words we haven't heard used by him or any other service company so far. He said: "The worsening market conditions added further pressure to a deepening financial crisis in the E&P industry, and prompted customers to make further cuts to already significantly lower E&P investment levels." On the conference call, Kibsgaard said 2015 was the worst industry downturn since 1986.
     
  2. 10,000 Lay-offs. Thursday's release confirmed that an additional 10,000 lay-offs have been implemented, taking total downturn lay-offs for the company up to 34,000. Seven weeks ago, we warned Oilpro readers that 10,242 lay-offs could be forthcoming at Schlumberger. The assessment, first published by Oilpro, was based on our interpretation of a financial disclosure in a Schlumberger SEC filing. In the company's 4Q earnings release, CEO Paal Kibsgaard said: “In anticipation of an extended activity weakness in the first half of 2016, we implemented another significant adjustment to our cost and resource base during the fourth quarter. This included a further workforce reduction of 10,000 employees, as well as greater streamlining of our overhead, infrastructure and asset base." Importantly, CEO Kibsgaard said on the conference call that he believes the headcount is now the right size for 2016, implying there are no more layoffs expected. That could certainly change with market conditions, but it is encouraging none-the-less.
     
  3. Hoping For A Bottom In 2016, But Schlumberger Isn't Sure Yet. When asked on the conference call if everything will bottom in 2016, CEO Kibsgaard said: "Well, I think it's too early to say, but I don't currently think that 2017 is going to be worse. With that said, I'm still not ready to say that we are [hitting bottom] in 2016. We're focusing in on executing basically quarter-by-quarter. I'm still optimistic, and I would hope that 2016 is the trough but I'm not ready to rule on it yet." Schlumberger does expect positive movement in oil prices during 2016, with specific timing being a function of the shape of the non-OPEC decline rates.
     
  4. Abrupt Work Cancellations By Customers Are A Key Theme In The Release. CEO Paal Kibsgaard cited "abrupt" cancellations and activity disruptions several times throughout the press release. This is new and shows the severe strain on operators and rising unpredictability and counter-party risk for oilfield contractors. On the call, Kibsgaard said: "unscheduled and abrupt activity cancellations [are] creating an operating environment that is increasingly complex to navigate." Some of this was a 4Q phenomenon as budgets ran out, but this is something to watch in 2016.
     
  5. Schlumberger May Buy Back Up To $10 Billion Of Its Downtrodden Stock. Schlumberger's stock has fallen almost 50% in 18 months. This fall may have something to do with the renewal of the company's existing and almost exhausted $10 billion dollar share repurchase program Thursday. During 2015, SLB bought back $2.2bn of its stock, nearly completing its authorization. Thursday, perhaps partly motivated by the current stock price, the company announced a $10 billion re-load of the buyback. On Friday, CEO Kibsgaard said of capital deployment: "We're not increasing dividends this year. Beyond that, for the coming year it's going to be a balancing of the opportunities we have on M&A and the opportunities we have to buy back our stock."
     
  6. Asset Write-Offs In Full Swing. SLB Takes A $1.6 Billion Hit. CEO Kibsgaard said in the press release that the company took a "largely non-cash $1.6 billion pretax impairment charge for fixed assets, inventory write-downs, facility closures, contract terminations, and other asset impairments." This marks the start of what we expect to be a steady stream of capacity write-offs this quarter - for both E&P and oilfield service firms. It is part of the painful rebalancing process as management teams calibrate organizations built for $100 oil to new price realities.
     
  7. Cameron Deal To Close By March. The Cameron integration plans are complete. The integration will be simple. Cameron will become the fourth product group at Schlumberger, adding to characterization, drilling, and production. Scott Rowe, Cameron's CEO, will lead the product group, and Cameron will largely maintain its present form. The customer interface will change, the back office will be streamlined, and R&D will eventually merge into Schlumberger.
     
  8. E&Ps Are Rethinking The Way They Do Things. New technology sales (products developed within 5 years) comprised 24% of 2015 revenue for Schlumberger, markedly higher than what we saw in the previous downturn in 2008, 2009. This is a sign E&Ps are thinking outside the box to cut costs.
     
  9. Oil Production Declines Coming To Rebalance The Market. In North America shale oil production is declining more or less as Schlumberger expected, and was, in December, below the levels from one year ago. The apparent resilience in production outside of OPEC and North America is in many cases driven by producers opening the taps wide open to maximize cash flow, which also means that we will likely see higher decline rates after these short-term actions are exhausted.
     
  10. When Things Do Recover, Deep Costs Cuts Make Oil Service A Coiled Spring. Schlumberger thinks their international business is a highly compressed coiled spring, which will see profits surge when E&P investments start recovering.
  • North Dakota Pipeline Approved.  North Dakota regulators this week approved their state’s portion of the $3.8 billion, 1,150-mile, and 600,000 barrels per day (BPD) Dakota Access crude oil pipeline.

    The 30-inch line will flow crude from the Bakken/Three Forks plays in northwest North Dakota, through North and South Dakota and Iowa, before ending at Patoka, Illinois, Kallanish Energy learns.

    The North Dakota Public Service Commission had been reviewing Dallas-based Energy Transfer Partners’ permit for 13 months. The three-member, all-Republican panel said the pipeline would reduce truck and oil train traffic, cut natural gas flaring and create more markets for the state’s oil and gas.

    The commission voted 2-0 to approve the permit; Commissioner Randy Christmann abstained because his mother-in-law has been negotiating an easement for the project, The Associated Press reported.

    Energy Transfer Partners hopes to complete the pipeline by year’s end.

    Regulators in South Dakota and Illinois have already approved permits. Iowa remains, though Energy Transfer said it expects approval to come next month.

    The U.S. Army Corps of Engineers also must approve the line because it would cross beneath the Missouri River twice in North Dakota.
     
  • Drawdown in NatGas Storage.  Colder temperatures caused the largest drawdown of the 2015-2016 heating season thus far, the U.S. Energy Information Administration reported Thursday.

    At Jan. 15, working gas in storage in the Lower 48 States totaled just under 3.3 trillion cubic feet (Tcf), down 178 billion cubic feet (Bcf) from 3.48 Tcf one week earlier, Kallanish Energy finds.  

    All five regions the EIA divides the U.S. into reported week-to-week drawdowns, the highest volumes reported in the Midwest, South Central and East regions.
     
  • Williams Cuts CAPEX by 33%.  Pipeline giant Williams and its Williams Partners affiliate said Monday Williams Partners’ 2016 capital budget for growth was chopped by $1 billion – 33% — to $2 billion, Kallanish Energy learns.

    Williams also said it’s maintaining its quarterly dividend at 85 cents a share. Williams Partners’ current yield is now 15%.

    The sharp cut in 2016 capital and investment expenditures includes project deferrals, delays and cancellations due to current commodity prices and sharply higher costs of capital.

    “Our strategy remains intact and the underlying fundamentals of our business are strong despite the slower growth rates producers currently face,” said Alan Armstrong, CEO of Williams Partners’ general partner. “Our revised capital plan addresses the realities of our current market environment while continuing to invest in the growing demand side of our business.”

    The $2 billion growth capital funding needs include $1.3 billion for Transco (pipeline) expansions and other interstate pipeline growth projects, most of which are fully contracted with investment-grade customers.

    Non-interstate pipeline growth capital funding needs total $700 million, primarily reflecting relatively modest additional investments across the partnership’s gathering and processing systems.

    Capital spending for gathering and processing in 2016 will be limited to known new producer volumes, including wells drilled and completed awaiting connecting infrastructure, Williams said.
     
  • Consol 4th Qtr.  Results.  Production increased by over 35% in the just-ended quarter, when compared to the year-earlier quarter. Despite increased production, total quarterly outside sales revenue decreased by $10.1 million for the same period due to depressed commodity prices. Despite a reduction in sales revenue, the E&P Division realized net income of $57.1 million in the fourth quarter of 2015, compared to $36.5 million in the year-earlier quarter.

    During the fourth quarter of 2015, the E&P Division's total unit costs, including depreciation, depletion, and amortization (DD&A), declined to $2.45 per Mcfe, compared to $3.19 per Mcfe during the year-earlier quarter. Full year 2015 E&P Division total unit costs were $2.73 per Mcfe, including DD&A, or an improvement of $0.58 per Mcfe, compared to $3.31 per Mcfe in the prior year. For the E&P Division, full year 2015 total unit costs were slightly below the low-end of the previously stated guidance range of $2.74-$2.84 per Mcfe.

    As expected, E&P Division capital declined significantly in the fourth quarter to $83.4 million due to the company laying down all operated rigs late in the third quarter of 2015.

    GH 9 (Greene County, Pennsylvania):

    CONSOL Energy completed its second successful test of the dry Utica/Point Pleasant formation on the company's acreage in Pennsylvania. CONSOL's GH 9 well located in Greene County, Pennsylvania, had an initial 24-hour flow test of 61.9 MMcf per day at an average flowing casing pressure of 8,312 psi. CONSOL has a 100% working interest and 96% NRI in the well, which was completed with a 6,141 foot lateral and 30 frac stages.

    Gaut 4I (Westmoreland County, Pennsylvania):

    In the third quarter of 2015, CONSOL Energy announced its first dry Utica test well, the Gaut 4I, in Westmoreland County, Pennsylvania, which had an initial 24-hour flow test to sales of 61.4 MMcf per day at an average flowing casing pressure of 7,968 psi. CONSOL has a 100% working interest and 87.5% NRI in the well, which was completed with a 5,800 foot lateral and 30 frac stages. The company subsequently conducted flow tests to ascertain the deliverability of the reservoir and well drainage, which have provided critical information on pressure draw-down management and inter-lateral spacing for future Utica Shale development. Following the flow tests, the Gaut 4I well produced for approximately one month at an average rate of approximately 19 MMcf per day, with limited pressure draw-down of 20-25 psi per day. To-date the well has produced 1.26 Bcf in 60 days of operations, while average flowing casing pressure is approximately 8,100 psi. CONSOL Energy expects to manage casing pressure draw-down over time, until reaching line pressure of approximately 800-1,000 psi. During this extended draw-down phase, CONSOL expects production volumes to be relatively flat for 9-12 months after which it will enter its hyperbolic decline phase.

    Switz 6 (Monroe County, Ohio):

    CONSOL Energy brought online the Switz 6D well in October 2015 on its 4-well dry Utica pad, located in Monroe County, Ohio, at an initial production rate of 44.7 MMcf per day with average flowing casing pressure of 6,835 psi. To-date, the Switz 6D well has been online for 30 days and has cumulatively produced approximately 488 MMcf. As of January 18, 2016, the Switz 6D well was producing at 19.6 MMcf per day with average flowing casing pressure of 7,150 psi.

    Also during the fourth quarter, CONSOL completed and turned-in-line the three remaining dry Utica wells on the Switz 6 pad: the Switz 6F, 6H, and 6B wells. The Switz 6F and 6H wells had initial production rates of 23.7 MMcf per day and 25.2 MMcf per day with average casing pressure of 6,752 psi and 6,480 psi, respectively. These two wells were drilled and completed in the Utica formation with lateral lengths of 10,127 feet and 9,035 feet, respectively. As of January 18, 2016, the Switz 6F was producing at approximately 20.0 MMcf per day with flowing casing pressure of 7,113 psi, and the Switz 6H was producing at approximately 18.2 MMcf per day with flowing casing pressure of 6,900 psi. Both the Switz 6F and 6H are on a managed production plan. The Switz 6B well had an average initial production rate of 15.2 MMcf per day at an average flowing casing pressure of 5,532 psi. The Switz 6B was drilled and completed with a 6,145 foot lateral.

    The Switz pad wells were completed with varying stimulation techniques and materials such as sand, ceramic, resin, and resin tailed-in proppant. The estimated cost savings of utilizing 100% sand proppant versus 100% ceramic proppant in the stimulation process is approximately $2.5 million per well. The company will evaluate the data collected to-date, as well as future production results, to determine the optimal completion methodology in the Ohio Dry Utica, while weighing initial production versus completion costs.

    "The company continues to rapidly implement lessons learned from drilling and completing dry Utica Shale wells, as illustrated by reducing drilling costs per foot by nearly 50% from the first to the last well drilled in Monroe County, Ohio," commented Timothy C. Dugan, COO-E&P Division. "Based on initial data from the first set of operated and non-operated wells, CONSOL believes it can further reduce drilling and completion costs at or below the $10 million targeted goal, assuming a 7,000 foot lateral. For the Switz 6 pad, CONSOL has a 100% working interest and an average NRI of 80%."

    MND 6H -Non-operated (Marshall County, West Virginia):

    In the fourth quarter of 2015, the MND 6H dry Utica Shale well was brought on-line and production reached 60 MMcf per day during flowback operations. This well was drilled on a joint venture Marcellus pad. The MND 6H well, located in the Moundsville area, is part of the prior sale of approximately 3,000 acres to Noble Energy, which CONSOL executed in 2014. CONSOL believes that the 9,345 foot lateral is the longest Utica lateral drilled in West Virginia to-date. CONSOL has a 50% working interest in the well with a 49% NRI. Currently, the well is producing 20 MMcf per day with managed pressure draw-down of approximately 15-20 psi per day. CONSOL believes production from this well will remain flat for an extended period.
     
  • NE Pipeline Projects.  A number of recently completed and upcoming natural gas infrastructure projects are expected to increase the reach of natural gas produced in the Marcellus and Utica regions of the Northeastern United States (see map). These projects are intended to transport natural gas from production centers to consuming markets or export terminals.

    Over the past several years, natural gas production in the Marcellus and Utica areas has grown significantly: their combined growth of 12 billion cubic feet per day since 2011 accounts for 89% of the United States’ total growth in natural gas production. The Marcellus and Utica shale plays are located primarily in Pennsylvania, West Virginia, and Ohio. The pipeline infrastructure discussed here is mainly in the Northeast region, which includes Pennsylvania and West Virginia, but not Ohio, based on the regional breakouts in EIA’s natural gas pipeline data.

    Partly as a result of strong domestic production growth, both domestic natural gas consumption and exports of natural gas by pipeline have increased, and exports of liquefied natural gas (LNG) from the United States are set to begin this year. However, because infrastructure projects often have longer lead times than production projects, infrastructure growth in the Northeast has not kept pace with production growth, and capacity has been insufficient to move natural gas out of the Northeast to demand centers and export locations.

    In the past several months, several new pipeline projects have come online to move natural gas either to nearby market areas in the Mid-Atlantic area (New York, New Jersey, and Pennsylvania) or to feed into existing infrastructure that delivers natural gas to more distant regions, especially the U.S. Gulf Coast.

    Key projects that came online in late 2015 or early 2016 include:

    The Rockies Express Pipeline (REX) reversal project had added westbound capacity to flow natural gas to the Midwest in 2014. In late 2015, Texas Eastern Transmission Company’s (Tetco) OPEN project added 550 million cubic feet per day (MMcf/d) of pipeline takeaway capacity out of Ohio.

    Columbia Gas Pipeline’s East Side Expansion, a 310 MMcf/d project that flows natural gas produced in Pennsylvania to Mid-Atlantic markets.

    Tennessee Gas Pipeline’s Broad Run Flexibility Project, a 590 MMcf/d project originating in West Virginia that moves natural gas to the Gulf Coast states.

    Tetco’s Uniontown-to-Gas City project flows up to 425 MMcf/d of natural gas produced in the Marcellus region to Indiana.

    Williams Transcontinental Pipeline’s Leidy Southeast project provides additional capacity to take Marcellus natural gas to Transco’s mainline, which extends from Texas to New York. From there, the natural gas serves Mid-Atlantic market areas as well as the Gulf Coast.



    Several other projects plan to add natural gas transmission capacity later in 2016: The Algonquin Incremental Markets expansion project will add 342 MMcf/d of capacity to Algonquin Gas Transmission’s pipeline in the highly constrained New England region. The Constitution Pipeline will have the capacity to transport up to 650 MMcf/d of natural gas from the Appalachian Basin to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, which will provide access to markets in the Northeast and New England. The Wright Interconnect Project expands Iroquois’s facilities and supports the Constitution Pipeline where the Iroquois and Constitution pipelines interconnect in Wright, New York.

    Other projects currently under construction, including liquefaction projects in Maryland and along the U.S. Gulf Coast, will enable natural gas produced in the Appalachian Basin to reach markets overseas.

Visit our Blog for daily updates on what’s happening in the oil & gas industry

http://www.shaledirectories.com/blog/

Rig Count

  • Baker Hughes Rig Count the week of January 29, 2016
     
  • PA
    • Marcellus 22 down 1
    • Utica 0  
  • Ohio
    • Utica 14 unchanged
  • WV
    • Marcellus 12 unchanged
  • TX
    • Eagle Ford – 64 unchanged
    • Permian Basin  158 down 13
  • NM
    • Permian Basin – 24 down 4
  • ND
    • Williston – 44 down 1
  • CO
    • Niobrara – 19 up 2
       
  • TOTAL U.S. Land Rig Count 591 down 17

PA Permits for January 21, to January 28, 2016

       County            Township            E&P Companies

1.    Beaver              New Sewickley    PennEnergy
2.    Bradford           Columbia             Talisman
3.    Butler              Summit                XTO
4.    Elk                  Horton                 EQT
5.    McKean           Norwich              Seneca
6.    Susquehanna   Bridgewater         Cabot
7.    Tioga               Morris                 SWN

OH Permits for week ending January 23, 2016

County            Township                E&P Companies

1.          There were no permits this week in OH.

Joe Barone jbarone@shaledirectories.com 610.764.1232
Vera Anderson vera@shaledirectories.com 570.337.7149

Midstream PA