Oil & Gas Production Monitor

Transcription

1 For Questions contact Matt Andre at Oil & Gas Production Rig Count This Month Last Month National PADD I Inside This Issue Marcellus Dry Pg. 9 North PA. Pg. 11 South PA. Pg. 15 WV Dry. Pg. 19 Marcellus Wet & Utica Pg. 22 SW PA... Pg. 24 WV Wet... Pg. 28 Ohio.... Pg. 31 New York.. Pg. 35 Kentucky.. Pg. 37 Virginia.... Pg. 39 PADD I.... Pg. 41 Highlights and Key Points Feature: Expansions for 4Q215 (pg. 4) Projection Methodology (pg. 5) Antero s Realized Gas Price (pg. 5) Producer Updates (pg. 5) Internal Rate of Return Commentary (pg. 5) Internal Rate of Return Play-by-Play (pg. 6) Click here for the PADD 1 Production data file. Click here for the Gas Production data file. October 215 Oil & Gas Production by Area PADD 1 Oil Production (Mb/d) Aug-15 Sep-15 Oct-15 Nov-15 Dec PADD 1 Oil Production US Total (incl Alaska) 9,37 9,47 9,388 Gas Production (Bcf/d) Aug-15 Sep-15 Oct-15 Nov-15 Dec Current Projection US L48 Total (Cellcast ) *CellCast: Bentek s balanced national forecast product Mb/d PADD 1 Oil Production Bcf/d Natural Gas Production Historical Projection Interstate Sample Projection Copyright 215 BENTEK Energy

2 October 215 Oil & Gas Production by Area PADD 1 and OH & KY Oil Production (Mb/d) Producing Region Aug-15 Sep-15 Oct-15 Nov-15 Dec Alabama Florida Georgia Maryland New York Pennsylvania Virginia West Virginia PADD 1 Total Ohio Kentuky Total Gas Production (Dry - MMcf/d) Producing Region Aug-15 Sep-15 Oct-15 Nov-15 Dec Kentucky New York Ohio 3,74 3,741 3,761 3,49 Pennsylvania 12,954 13,123 13,284 13,181 Virgina West Virgina 3,152 3,132 3,227 3,23 Total 2,32 2,485 2,758 2,316 PADD 1 Oil Production by Area Natural Gas Production by Area Mb/d Bcf/d NY PA VA WV Florida KY OH NY PA VA WV Copyright 215 BENTEK Energy

3 October 215 PADD 1 Active Rigs by Drilling Target PADD 1 Active Rigs by Drilling Orientation # of Rigs # of Rigs Total Gas Oil O&G Total Hor Ver Dir Source: Bentek, RigData Source: Bentek, RigData Active Rigs by Drilling Target Active Rigs by Drilling Orientation # of Rigs # o Rigs Total Gas Oil O&G Total Hor Ver Dir Active Rig Count by Area for Week: 9/25/15 Well Class Orientation Region Gas Oil Oil/Gas Hor Dir Ver Total North Pennsylvania South Pennsylvania West Virginia Dry SW Pennsylvania West Virginia Wet Ohio New York Kentucky Virginia Copyright 215 BENTEK Energy

4 October 215 4Q215 Expansion Projects In light of the impending (NE) expansion projects expected to commence service in the fourth quarter, this month s feature will focus on the concern of potential underwhelming utilization on future NE take-away capacity projects. As current commodity prices remain suppressed, there is growing speculation that take-away projects will not flow at 1% utilization as they commence service. Rocky Mountain Express East-to-West (REX E2W) expansion, which allows NE gas access to Midwest markets, increased capacity in August to 1.8 Bcf/d but since has been averaging 1.37 Bcf/d (peaking this past week at 1.47 Bcf/d). The chart below (taken from Bentek s Expansion Report) details fourth quarter expansion projects anticipated to bring 2.5 Bcf/d additional capacity online. The projects are broken out into two groups, NE Wet region (supporting eastern Ohio and SW PA), while the other projects are focused on NE PA production. The TETCO OPEN project was intended to come in-service Nov. 1 allowing Utica gas more outlets to neighboring markets. However, on September 15 the pipeline allowed early access to its subscribers providing partial service to the mainline facilities via compressor station upgrades. Initial flows seem to be displacing gas and optimizing transport opposed to bringing on new production. The new production aspect of the expansion intends to follow the original in-service date of Nov. 1 after the completion of the Ohio Extension Lateral allowing 55 MMcf/d take-away capacity onto TETCO. OPEN is 1% producer subscribed with Chesapeake accounting for 35 MMcf/d of the capacity. Chesapeake has curtailed approximately 275 MMcf/d of their Utica production, mentioning anticipation of the OPEN project along with weak in-basin natural gas & NGL prices as culprits. It is expected that the company will utilize capacity as it provides favorable basin transportation rates with delivery access to Gulf Coast markets. 7) are fully subscribed by Antero and s to Mexico. ess to ern and Southeastern ounty, AL and is an example of NE The question remains, as these projects commence service, will they run at capacity or slowly ramp up over time? In 214, the NE observed a trend where expansion projects were filling rapidly, conversely in mid-215 REX E2W has been hovering around 75% utilization for the past 2 months. If the NE 4Q215 projects run at 75%, the estimated total of 2.5 Bcf/d, drops to 1.9 Bcf/d. At 5% utilization the additional take-away capacity drops to 1.2 Bcf/d. Oct. 1 witnessed Henry Hub cash reach $2.37/MMbtu, its lowest point since mid-june 212, reinforcing the skepticism. On the demand side, the Southeast has potential for another.5 Bcf/d coal-to-gas switching available. This will not balance supply demand in the U.S., but any help by way of increased demand (or price uplift) would bring much needed relief to NE producers as these 4Q215 expansion projects finish construction. Sustainable demand relies on LNG exports projects expected to start service as early as 1Q216 and grow capacity to 1.1 Bcf/d through 22. Although, there is speculation that U.S. LNG exports will also be underutilized based on international competition, the uncertainty of commodity prices and global demand. Copyright 215 Bentek Energy

5 October 215 Regional Analysis & IRR Commentary Methodology The dry gas projection methodology leans heavily on Bentek s collection of production sample data, which is close to 96%. Sample data tracks pipelines and natural gas production receipt points giving insight into regional supply. Most production projections assume the current drilling activity and trends will continue into the future. The is unique because it also expects expansion projects (take-away capacity) will be filled by either new production or the stock of well inventory, estimated to be close to 19 Bcf/d. This number is derived by multiplying the 2,5 wells in inventory by an average IP rate of 7,6 Mcf/d for a rough estimation of trapped gas in the. The reason the NE strays from the traditional methodology is due to the lingering issue of pipeline constraints that has capped the NE growth since 213. Bentek assumes a good portion of the inventory is waiting for additional infrastructure to be put in place, but producers have made note that suppressed commodity prices has become a large factor for the inventory build up as well. Realized Gas Price In the current commodity pricing environment, how have producers been able to sustain drilling? One way is by leaning heavily on hedges put in place last year when Henry Hub averaged $4.27/MMbtu. As the year comes to a close and 215 hedges roll-off, producers could start feeling the full weight of the price collapse. Antero, one of the top producers, has observed a substantial drop in its 'average realized gas price' since 1Q215 according to its 215 earnings presentation. This price (factoring regional price and hedges) is a better indication of what producers are realizing for their natural gas as the commodity hits the market and turns the asset into cashflow. Antero s gas marked to Dom South/TETCO realized price has dropped significantly from its 1Q215 price of $2.85/Mcf to its 2Q215 price of $2.26/Mcf. This is in large part due to regional prices dropping 54 cents quarter-over-quarter. Similarly, the company s supply tied to the TCO region is down 47 cents, mainly attributed to NYMEX dropping from $2.98/Mcf to $2.64/Mcf quarter-overquarter. For context, Bentek s 1Q215 IRRs for the Dom South/TETCO region of the Marcellus were estimated at 2.8%. If we assume Antero s realized price, the IRR jumps to 2.9%. In the second quarter, the IRR according to Bentek is.8% and Antero s realized price brings the IRR to 8.2%. Producer News As 215 hedges roll-off, producers will continue to struggle with cashflow and liquidity concerns. Apparent in Chesapeake Energy s announcement on Tuesday to cut 15% of its workforce citing suppressed commodity price environment as the main culprit. Chesapeake is the #2 natural gas producer in the U.S. and employs over 5,5 people. The company currently owns ~3, net acres within the dry gas window of the Utica basin, as the area has been part of their growth plan for the past two years. This is one area they could contemplate selling non-core acreage if they are looking to alleviate some of the cashflow and debt burden, a dilemma affecting nearly all producers in 215. IRR Texas Continues to Lead the Stack With prices for oil, gas and NGLs remaining relatively flat month-over-month, there has been little to no change to the IRR stack for October when compared to last month. October s average 12-month forward curve for Henry Hub is currently $2.85/MMbtu, down $.4/MMbtu from last month. On the oil side, the current WTI 12-month forward curve for October is $47/b, largely unchanged from a month ago. The 12-month forward curve price for an average NGL barrel is $19.25/b. This is derived from taking a weighted NGL price based on each region s unique NGL barrel composition. The Permian Delaware basin located in West Texas still leads the stack with a typical well earning a 23% return. The Delaware boasts an average oil IP rate of 55 b/d which represents 75% of the production mix. The oil window of the Eagle Ford is second on the stack with an IRR of 17%. A typical well in the Eagle Ford oil window has an oil IP rate of 6 b/d, accounting for 73% of the production mix. The major disparity between the plays is the price differential received on their crude oil, with the Eagle Ford product discounted about $6/b to the Permian Delaware due to the differences in quality. The Eagle Ford typically produces a much lighter grade of crude that often requires blending to run through Gulf Coast refineries. Drilling and completion costs for the two plays are close with the Eagle Ford estimated at $6.2MM and the Permian Delaware $6.6MM per a well. The IRR graph (on page 6) displays the production mix for a typical well in each play. The black diamond represents the IRR for the respective play (see the scale on the right hand side of the graph). It is clear the plays more heavily weighted towards oil (production mix) continue to earn the highest rates of return. The gas-rich plays, Marcellus and Utica, continue to hover close to breakeven as prices remain suppressed. Copyright 215 Bentek Energy

6 October 215 Marcellus/ Utica Regional Map Copyright 215 BENTEK Energy

7 October 215 Midstream Infrastructure Map Copyright 215 BENTEK Energy

8 October 215 DISCLAIMER. THIS REPORT IS FURNISHED ON AN AS IS BASIS. BENTEK DOES NOT WARRANT THE ACCURACY OR CORRECTNESS OF THE REPORT OR THE INFORMATION CONTAINED THEREIN. BENTEK MAKES NO WARRANTY, EXPRESS OR IMPLIED, AS TO THE USE OF ANY INFORMATION CONTAINED IN THIS REPORT IN CONNECTION WITH TRADING OF COMMODITIES, EQUITIES, FUTURES, OPTIONS OR ANY OTHER USE. BENTEK MAKES NO EXPRESS OR IMPLIED WARRANTIES AND EXPRESSLY DISCLAIMS ALL WARRANTIES OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE. RELEASE AND LIMITATION OF LIABILITY: IN NO EVENT SHALL BENTEK BE LIABLE FOR ANY DIRECT, INDIRECT, SPECIAL, INCIDENTAL, OR CONSEQUENTIAL DAMAGES (INCLUDING LOST PROFIT) ARISING OUT OF OR RELATED TO THE ACCURACY OR CORRECTNESS OF THIS REPORT OR THE INFORMATION CONTAINED THEREIN, WHETHER BASED ON WARRANTY, CONTRACT, TORT OR ANY OTHER LEGAL THEORY. ICE PRICE DATA: ICE Index Data used herein is provided under BENTEK s AGREEMENT FOR THE PROVISION OF INDEX DATA with ICE. Recipients of this report acknowledge that the ICE Index Data and reports thereon are confidential and are proprietary trade secrets and data of either Distributor or its licensors/suppliers. Recipients shall use best efforts to prevent the unauthorized publication, disclosure or copying of the ICE Index Data. Recipient may use ICE Index Data solely for valid purposes related to its own internal business activities and for no other purpose. NO WARRANTIES, LIABILITIES, OR OBLIGATIONS ARE ASSOCIATED WITH ICE INDEX DATA, INCLUDING WITHOUT PREJUDICE TO THE GENERALITY OF THE FOREGOING, THE IMPLIED CONDITIONS OR WARRANTIES OF MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, AND NON-INFRINGEMENT. Forward basis and price data provided by NYMEX ClearPort. Methodological Notes Some data in this report are derived from BENTEK Energy s proprietary Energy Data Warehouse. BENTEK collects and monitors natural-gas pipeline nominations as posted on individual pipeline electronic bulletin boards (EBBs). BENTEK has assigned geographic and usage descriptions, such as state, province, county, production region, customer type and connected party to more than 26, pipeline points. The descriptions assigned to these pipeline data points enable users to monitor and forecast U.S. production, U.S. imports, U.S. LNG sendout, demand from multiple sectors and storage injection and withdrawal activity. BENTEK's PRODUCTION PROJECTIONS are based on state wellhead production data provided by HPDI, LLC. Each projection starts from the last completed dataset and then projects production into the future using type-curves for each basin based on drilling orientation and resource target. BENTEK does not assume a base decline rate in its production projections. Production is forecasted on a well-by-well basis based on the current producing age of each well and where production from that well is on its current decline curve. Well counts are assumed to be flat from the previous month's drilling level, except where noted due to basins with an inventory of wells that are awaiting pipeline expansions and/or completions. INTERNAL RATE OF RETURN (IRR) ANALYSIS: BENTEK has developed a financial model to calculate a representative internal rate of return (IRR) for a typical well in each of the major plays in the United States. Company financials, including 1Qs, 1Ks, investor presentations, news releases and transcripts from earnings calls are reviewed and production data is collected for each play. This producer-reported data is collected for each component of the IRR analysis, including drilling and completion costs, operating expenses, initial production rates, BTU content, decline curves, production taxes and royalty rates. This production data is then reviewed in order to determine a representative set of assumptions for each play. The IRR model is a discounted cash flow model and uses a 1% discount rate to calculate the IRR for a typical well in each play. Price assumptions are noted on the IRR charts. The IRR analysis does not take into account full-cycle costs, such as acreage acquisition and exploration costs, as BENTEK considers these expenses to be sunk costs. CellCast: The methodology and modeling behind CellCast data is designed to provide historical estimates and forecasts of natural gas production in each BENTEK Cell region; imports and exports among Canada, the U.S. and Mexico; gas flows among regions; regional LNG imports (sendout) and exports; and demand from power, industrial, residential, commercial and industrial facilities. BENTEK utilizes pipeline flow data as its primary information source, but in order to produce estimated historical data and forecasts, additional sources are required, including state production data, federal supply and demand data from the Energy Information Administration (EIA) and other agencies, weather data, data from the Mexican government, PEMEX, the Canadian provinces and the Canadian government, and other sources. Estimates of regional gas production are based on the relationship between monthly state production data from HPDI and daily nominations on pipelines. Dry gas estimates also are based on BENTEK's estimated NGL/Other shrink by basin. Copyright 215 BENTEK Energy

9 Rig Count Oil & Gas Production Marcellus Dry North/Central & South PA and WV Dry October 215 Rig Count This Month Last Month and Crude Oil Projections (Mb/d) Aug-15 Sep-15 Oct-15 Nov-15 Dec Oil Production and Gas Projections (MMcf/d) Aug-15 Sep-15 Oct-15 Nov-15 Dec Current Projection 12,946 13,34 13,172 13,168 Interstate Sample* 1,91 11,31 1,83 - * BENTEK Flow Sample 82% of Actual 12 Oil Production 2 Gas Production Mb/d Bcf/d Historical Projection Interstate Sample Projection Year-to-Date New Well Starts Horizontal Vertical Directional Total Gas Oil & Gas Oil Gas Oil & Gas Oil Gas Oil & Gas Oil Operator Equitable Southwestern Energy National Fuel Exploration Cabot Oil & Gas Chevron Consol Gas Talisman Energy Chesapeake Range Resources Vantage Energy Appalachia Other Operators Total Change from last year -19% -2% n/a % n/a -64% % n/a n/a -23% Copyright 215 BENTEK Energy

10 Rig Count Oil & Gas Production Marcellus Dry October 215 Top Operators - Ranked on Active Rig Count Week: 9/25/15 Well Class Orientation Operator Gas Oil Oil/Gas Hor Dir Ver Total Equitable Cabot Oil & Gas National Fuel Exploration Shell SWN Production Company Talisman Energy Vantage Energy Appalachia Natural Energy P L RESOURCES Range Resources Chesapeake Chevron JKLM ENERGY LLC Total Active Rigs by Drilling Target 14 Active Rigs by Well Orientation # of Rigs 8 6 # of Rigs Total Gas Oil O&G Total Hor Ver Dir Rig Count Summary Active Rigs Operator Peak Prior 4 Week Week Ending 9/24/1 Average 9/4/15 9/11/15 9/18/15 9/25/15 Equitable National Fuel Exploration Cabot Oil & Gas SWN Production Company Shell Vantage Energy Appalachia Natural Energy Range Resources Chesapeake JKLM ENERGY LLC Other Operators TOTAL Percent Change From Peak -82% Copyright 215 BENTEK Energy

11 The following sections were omitted from this SAMPLE edition of Bentek s Oil and Gas Production North Pennsylvania South Pennsylvania Dry West Virginia Dry Marcellus Wet and Utica Southwest Pennsylvania Wet South Pennsylvania Wet West Virginia Wet Ohio Utica Watch New York Kentucky Virginia PADD 1 (Supply) PADD 1 (Imports/Refinery) To subscribe to the complete edition of this report, please contact your BENTEK account representative, call BENTEK Sales at or info@bentekenergy.com.