US Natural Gas Reservoir

Transcription

1 3 August 23 Securities Research& Analytics US Natural Gas Reservoir The Credit Suisse Connections Series leverages our exceptional breadth of macro and micro research to deliver incisive crossasset and cross-border thematic insights for our clients. Research Analysts COMMODITIES RESEARCH Stefan Revielle stefan.revielle@credit-suisse.com Jan Stuart jan.stuart@credit-suisse.com EQUITY RESEARCH Arun Jayaram arun.jayaram@credit-suisse.com Helen Xu helen.xu@credit-suisse.com Connection Series Premium Northeast gas market fizzles Our take: Breakneck Marcellus supply growth has caused a dramatic swing in NE basis differentials relative to NYMEX (Henry Hub). Following the completion of the first of many processing plants in June, daily basis differentials at the Dominion South hub fell negative to lows of $.6/Mcf. Based on our regional supply and demand work, we expect wider NE disparities may continue indefinitely in Appalachian gas markets, with longer-term differentials poised to be $.2/Mcf to $./Mcf below NYMEX (versus the long-term premium of $.2/Mcf). New York and New England markets may be the next bubble to burst as they become increasingly connected with Marcellus/Utica supplies. Marcellus growth continues to outperform. Despite low levels of dry gas drilling activity, natural gas production continues to climb, with YoY gas production up 3% or 2. Bcf/d. Pipeline flows suggest that total NE supply is up 4. Bcf/d, more than offsetting declines in other key dry gas basins totaling.7 Bcf/d. Northeast supply is bound to continue its growth pace, particularly with Utica shale activity ramping up. Infrastructure has struggled to keep pace with supply, but a laundry list of pipeline projects aim to increase connectivity with Appalachian production. Over half of the.7 Bcf/d of pipeline capacity added in the US in 22 was located in the Northeast and could increase another 6.6 Bcf/d through 24, helping to further move Marcellus/Utica gas to market. In fact,.7 Bcf/d of pipeline expansions alone target the New York/New Jersey markets in 2H3. Natural gas processing capacity is adding to gas supplies, but may be constrained by limited NGL demand and pipeline capacity. Natural gas processing capacity in the wet-gas regions of the Marcellus and Utica is poised to increase 2.4 Bcf/d and 2. Bcf/d of in 23 and 24 respectively, adding substantially to gas and NGL supplies. However, limited northeast NGL demand and ethane rejection is causing gas richness to exceed pipeline BTU specifications in some areas. NGL pipeline capacity could increase nearly mb/d over the next three years to address this growing issue. Meanwhile Northeast gas demand markets are transforming but not nearly fast enough. With Northeast power demand only expected to see 4 MMcf/d of cumulative gas demand growth through 26, other options are needed to synthetically create demand. Backhaul pipeline projects and access to US LNG export terminals will help alleviate regional supply induced price pressures, but all major projects go in service no earlier than 2H 27. Northeast basis markets, we think, will see sustained weakness. Over the next 6-2 months, pipeline projects adding substantial import capacity to the NJ/NY markets place TETCO M3, Transco Z6 (non-ny) and Transco Z6 NY at additional risk to sell-off. For New England pricing points Algonquin and Iroquois, the newly commissioned Deep Panuke offshore project in Nova Scotia and the addition of 2 MMcf/d of pipeline capacity bringing Marcellus gas will help reduce the size and occurrences of wintertime basis blowouts. DISCLOSURE APPENDIX CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, INFORMATION ON TRADE ALERTS, ANALYST MODEL PORTFOLIOS AND THE STATUS OF NON-U.S ANALYSTS. FOR OTHER IMPORTANT DISCLOSURES, visit or call + (877) for Credit Suisse Equity Research disclosures and visit or call + (22) for Credit Suisse Fixed Income Research disclosures. US Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. CREDIT SUISSE SECURITIES RESEARCH & ANALYTICS BEYOND INFORMATION Client-Driven Solutions, Insights, and Access

2 3 August 23 Table of Contents Same old story on supply 3 Infrastructure struggling to keep up with supply 7 Northeast gas demand options are limited until 26 NE basis: Permanent dislocation or a short term anomaly? Maps and complete project lists: 3 CS Supply Demand Model and Price Forecast 7 Pricing Trends and Trading Statistics 8 Supply 22 US Imports/Exports 26 US Gas Demand (Monthly) 27 US Gas Demand (Annual) 28 US Gas Demand (YTD) 3 Natural Gas Storage 32 North America Rig Count and Permits 33 North America Gas Basin-Level Trends 34 Competitive Fuel Sources 36 US Natural Gas Reservoir 2

3 Jan-8 Mar-8 May-8 Jul-8 Sep-8 Nov-8 Jan-9 Mar-9 May-9 Jul-9 Sep-9 Nov-9 Jan- Mar- May- Jul- Sep- Nov- Jan- Mar- May- Jul- Sep- Nov- Jan-2 Mar-2 May-2 Jul-2 Sep-2 Nov-2 Jan-3 Mar-3 May-3 Jul Feb-6 Jun-6 Oct-6 Feb-7 Jun-7 Oct-7 Feb-8 Jun-8 Oct-8 Feb-9 Jun-9 Oct-9 Feb- Jun- Oct- Feb- Jun- Oct- Feb-2 Jun-2 Oct-2 Feb-3 Jun-3 3 August 23 Same old story on supply Exhibit illustrates historical differential basis between Appalachia gas (Dominion South & TCO) prices and NYMEX. Surging supply growth from the Marcellus Shale has caused a dramatic swing in NE basis differentials relative to NYMEX (Henry Hub). Exhibit : Appalachia differential (Average of Dominion South and TCO) ($/MMbtu) Appalachia vs. NYMEX Differential $. Appalachia - NYMEX Differential Average $.8 $.6 $.4 3Q3 QTD Avg. Price differential -$.2 vs. $.8 LTA $.2 $. ($.2) ($.4) Source: Natural Gas Week, Credit Suisse Exhibit 2: US dry gas production Exhibit 2 illustrates Lower 48 dry gas production implied by pipeline scrapes. Despite the significant pullback in natural gas drilling activity, supply trends have been stubbornly sticky, with YTD production through August up 2.% or.3 Bcf/d. Meanwhile, YoY production (August 23 vs. August 22) is up 3.% or 2. Bcf/d. Dry Gas Production 7 As of August 23 Up 2.% YTD (+.27 Bcf/d) Up 3.% Yr/Yr (+.96 Bcf/d) Source: Bentek Energy, Credit Suisse US Natural Gas Reservoir 3

4 Bcfe 3 August 23 The key basin that continues to drive resilient production trends is the Marcellus Shale and the Northeast more generally. Exhibit 3 and Exhibit 4 illustrate production trends in the Marcellus relative to the remainder of the gas market. While production ex-marcellus has declined by.7 Bcf/d YoY, the Marcellus Shale has more than outweighed this decline, growing 4. Bcf/d based on pipeline flows. Exhibit 3: Northeast is keeping total supply afloat (Bcf/d) Exhibit 4: Northeast Supply more than 2 Bcf/d (Bcf/d) Total Supply Ex-NE Supply NE Supply Jan- Jan- Jan-2 Jan-3 Source: Bentek Energy, Credit Suisse 2 Jan- Jan-6 Jan-7 Jan-8 Jan-9 Jan- Jan- Jan-2 Jan-3 Source: Bentek Energy, Credit Suisse What has been driving significant increases in reserves and production has been meaningful increases in Marcellus EURs per play, driven by sweet spot identification, improved frac recipes, and the optimization of lateral lengths. Since 2, we estimate that average Marcellus EURs have increased from 3.9 to 6.6 Bcfe (69%). Exhibit : Marcellus EURs Marcellus Shale EURs Source: HPDI, Credit Suisse estimates US Natural Gas Reservoir 4

5 SUSQUEHANNA DODDRIDGE GREENE LYCOMING WASHINGTON WETZEL BRADFORD HARRISON WESTMORELAND BUTLER FAYETTE MARSHALL FOREST MARION OHIO WYOMING BARBOUR CLEARFIELD TIOGA TYLER UPSHUR 3 August 23 Improving science is leading to bigger/better well results Our estimates could prove conservative given the widespread use of Reduced Cluster Spacing (RCS) and rotary steerables as we learned during our recent investor trip to the Marcellus. RCS completions (tighter spacing between fracs stages resulting in more perfs per lateral), which was first discussed in early in 22, has become almost universally adopted in the Marcellus. Operators such as CNX have noted a 2% to 4% improvement in EURs after months of production history. REXX reported that using Super-Fracs (also RCS) on 2 wells in Butler County has also resulted in a flattening of the curve increasing EUR estimates, and initial application of the completion technique in the Utica has resulted in some of the best IP-rates on a lateral foot basis in the play. Operators are widely implementing the technique across the basin with spacing varying from -22 feet between stages. Marcellus operators have also seen a big uptick in EURs from geo-steering and optimal lateral placement. Rotary steerables enable producers to now keep 99% of the wellbore within the targeted zone compared to 8% without the tool. In addition, the technology allows for a sharper turn from the kick-off point to make a 9 degree turn; feet vs., ft, enabling the lateral to be exposed to an additional ~3 ft of net pay. These improvements have enhanced well performance and effectively increased EUR s by as much as a Bcf per, feet of lateral. For example, Range Resources (RRC) raised their Southwest Pennsylvania dry gas EUR by 63% to 2.2 Bcfe, while they raised their wet gas EUR by 4% to 2.3 Bcfe. Meanwhile, the company estimates success with downspacing pilots to acres, which would boost their resources potential by an incremental 2 to Tcfe. Exhibit 6-9 illustrate the rigcount for the Marcellus as well as the key counties. Despite the retrenchment in activity, improved well performance and rising productivity is more than offsetting lower activity, which is yielding continued production strength. Exhibit 6: Rich-gas rigs outnumber dry rigs today in the Marcellus (rigs) Exhibit 7: Pennsylvania rig counts by county (rigs) 6 4 Marcellus Total NE PA (Dry gas) SW PA (Wet-Gas) Yoy delta Current Rig Count Feb- Aug- Feb-2 Aug-2 Feb-3 Source: Baker Hughes, Credit Suisse Source: Baker Hughes, Credit Suisse US Natural Gas Reservoir

6 Gas Production (Bcf/d) Gas Production per Rig Jan-4 May-4 Sep-4 Jan- May- Sep- Jan-6 May-6 Sep-6 Jan-7 May-7 Sep-7 Jan-8 May-8 Sep-8 Jan-9 May-9 Sep-9 Jan- May- Sep- Jan- May- Sep- Jan-2 May-2 Monthly Well Completions per Rig 3 August 23 Exhibit 8: Kickoff to TD in -6 days for 6 laterals Days from kickoff to TD versus directional feet drilled in Marcellus Exhibit 9: Fewer rigs & quicker drill times = more completions and higher productivities Monthly well completions per rig Marcellus Productivity Source: Rice Energy, Credit Suisse Source: HPDI, Smith Bits, Credit Suisse estimates As a result of efficiencies and improving well performance, production per rig has increased significantly, as illustrated in Exhibit Exhibit : Time Series of Natural Gas Production Gas Production (Bcf/ d) Exhibit : Natural Gas Production per Rig Natural Gas Production per Rig 9 Barnett Fayetteville Marcellus Woodford Haynesville-TX/LA 3, Barnett Fayetteville Marcellus Woodford Haynesville-TX/LA 8 7 2, Efficiency zone 6 2, 4, Months Source: HPDI, Credit Suisse estimates, Efficiency zone, MARCELLUS IS GETTING EFFICIENT! Months Source: HPDI, Baker Hughes, Credit Suisse estimates Exhibit 2 illustrates our Basin production model for the Marcellus. Note we expect for supply growth to continue at a breakneck pace through 26. Northeast supply is bound to continue its growth trajectory, particularly with Utica shale activity ramping up. US Natural Gas Reservoir 6

7 Jan-6 Jul-6 Jan-7 Jul-7 Jan-8 Jul-8 Jan-9 Jul-9 Jan- Jul- Jan- Jul- Jan-2 Jul-2 Jan-3 Jul-3 Jan-4 Jul-4 Jan- Jul- Jan-6 Jul-6 MMcf/d 3 August 23 Exhibit 2: Marcellus Production Forecast Model Monthly forecast for PA section of Marcellus shale in MMcf/d Marcellus Production Forecast Model 4, 3, 2,,, 9, 8, 7, 6,, 4, 3, 2,, Historical Production Forecasted Production Source: HPDI, Credit Suisse estimates Infrastructure struggling to keep up with supply A number of pipeline expansion and processing plants additions should help alleviate many of the supply bottlenecks stemming from supply growth in the Northeast. Shown in Exhibit 3, over half of the.7 Bcf/d of the pipeline capacity added in the US in 22 was located in the Northeast and based on current plans could increase another 6.6 Bcf/d through 24 helping to further move Marcellus/Utica gas to market. Exhibit 3: Half of all added capacity in 22 and 23 is in the NE (Bcf/d) 6 Northeast Total US 4 Announced, planned or under construction We expect the remaining pipeline expansions in 23 to place downward pressure on NY/NJ basis prices. Of note, the NJ-NY expansion project, Northeast Upgrade project and the Northeast Supply Link Project (Exhibit 22) add nearly.7 Bcf/d of added supply to the New Jersey and New York Markets. US Natural Gas Reservoir 7

8 3 August 23 The Northeast Upgrade project, which will flow 636 MMcf/d of gas from the Tennessee Gas Pipeline s 3 line to Algonquin, coincides with the NJ-NY project which brings 8 MMcf/d of gas to Algonquin and TETCO to the NJ/NY areas including a delivery point onto Con-Edison s distribution system in Manhattan. The Northeast Supply Link project alleviates bottlenecks on Transco s Leidy Line in Pennsylvania by expanding Transco s existing system by 2 MMcf/d to provide firm transportation to delivery points in New Jersey and New York. Transco zone 6 (both NY and non-ny) as well as TETCO M3 should feel downward pressure on basis over the next 6-2 months. At the same time, natural gas processing additions are helping to alleviate rich-gas supply bottlenecks. Natural gas processing capacity in the wet-gas regions of the Marcellus and Utica aim to increase 2.4 Bcf/d and 2. Bcf/d of in 23 and 24 (Exhibit 4). Exhibit 4: Appalachian processing capacity additions (capacity in MMcf/d) Start-up Date (ISD) Status Plant State County Capacity (MMcf/d) 3//23 Online Mobley I, II WV Wetzel 32 //23 Online Majorsville III WV Marshall 2 /2/23 Online Cadiz I OH Harrison 2 /3/23 Online Natrium/44 - Phase I WV Marshall 2 /3/23 Online Sherwood II WV Doddridge 2 7//23 New Build Kensington OH Columbiana 2 7//23 Expansion Fort Beeler III WV Marshall 2 9//23 Expansion Natrium/44 - Phase II WV Marshall 2 9//23 Expansion Sherwood III WV Doddridge 2 //23 New Build Hickory Bend OH Mahoning 2 2//23 Expansion Majorsville V WV Marshall 2 2/3/23 Expansion Mobley III WV Wetzel //24 New Build Seneca I OH Noble 2 //24 Expansion Seneca II OH Noble 2 //24 New Build Seneca Interim OH Noble 4 3//24 Expansion Bluestone II PA Butler 2 3//24 Expansion Majorsville IV WV Marshall 2 3//24 Expansion Seneca III OH Noble 2 3//24 New Build Oak Grove I WV Marshall 2 6//24 New Build Leesville OH Carroll 2 6//24 Expansion Sherwood IV WV Doddridge 2 6//24 Expansion Bluestone III PA Butler 2 6//24 Expansion Majorsville VI WV Marshall 2 6//24 Expansion Cadiz II OH Harrison Source: Bentek Energy, Credit Suisse But limited local NGL demand and takeaway capacity is threatening Northeast pipeline specifications. The 2 MMcf/d Natrium processing plant in Northeast West Virginia became operational in late June and due to poor processing economics is fully rejecting ethane, electing to keep as much as possible in the gas stream. Since this time, Texas Eastern has issued two critical notices to shippers as ethane (C2+) levels reached levels higher than the specification of 2.%. To alleviate this rich-gas issue, purchases of dry gas from REX (at the REX/Clarington flow point) onto TETCO increased 3 MMcf/d to dilute the elevated C2+ levels and keep nearby power plants operational (Exhibit ). The influx of gas has caused Dominion South basis prices to collapse to daily lows nearly 7 cents under henry hub while also pressuring nearby TCO hub prices as well. US Natural Gas Reservoir 8

9 3 August 23 Exhibit : REX flows onto TCO increased when Natrium became operational (weekly average MMcf/d) 4, Rex/Clarington (lhs) Dom S $.2 3, $. 3, $. 2, -$. 2, -$.2, -$.3, 2 MMcf/d Natrium, processing plant becomes operational 2-May 8-Jun 22-Jun 6-Jul 2-Jul 3-Aug Source: Range Resources, Credit Suisse -$.4 -$. -$.6 Needed NGL pipeline capacity should help alleviate rich gas issues. To help relieve the now increasing northeast NGL-supply, ethane, propane and y-grade (raw NGL mix) pipeline export capacity out of the Northeast is expected to increase ~24 kb/d, 7 kb/d and 4 kb/d respectively over the next three years (see Exhibit 24 - Exhibit 26). Mariner West: kb/d ethane pipeline from Houston, PA to the existing Sunoco Logistics pipeline at Vanport, PA for shipment to the Sarnia, Ontario ethane market. The project became operational in July 23. ATEX Express: 9 kb/d ethane pipeline from Houston, PA to the Texas Gulf Coast region. Once complete, it will have direct access to Enterprise Products NGL storage complex in Mont Belvieu, TX. Target in-service date is Q4. Mariner East: 7 kb/d propane pipeline from Houston, PA to Delmont, PA where it will reach an interconnection with an existing Sunoco Logistics Pipeline to be transported to Marcus Hook, PA with the ability to reach both local and international NGL markets. The first stage of the project is estimated to be in service by 2H4 while an additional ethane option is targeted for H. Bluegrass: 2 kb/d y-grade pipeline would send NGLs from Ohio/West Virginia/Pennsylvania to the US Gulf coast to access fractionation capacity and petrochemical market with additional access to storage facilities. The project has the potential to increase capacity to 4 kb/d and is projected to go in-service during 2H Markwest Energy/Kinder Morgan JV project: Recently announced 2 kb/d y-grade pipeline directly competes with the Bluegrass project and sends NGLs from the Marcellus/Utica Shales to the Gulf Coast. The raw mix pipeline, like Boardwalk, has the option of being expanded to 4 kb/d and has a target in-service date of 2H. US Natural Gas Reservoir 9

10 3 August 23 Northeast gas demand options are limited until 26 The Northeastern US, like much of the North American gas market, has generally increased its reliance upon natural gas to meet its power, industrial and residential/commercial needs. In fact, over the period from January to July from 2-23, as average US demand flows increased ~2 Bcf/d, Northeastern US directed flows accounted for 2% of that growth or 2.6 Bcf/d. While impressive on its own, simultaneous supply gains of nearly 6 Bcf/d out of the Marcellus Shale more than outweighed improvements in demand and only thanks to an exceptionally cold spring (soon to be partially offset by a mild end of summer) is 23 holding on to nearly Bcf/d of gains yoy. Most importantly, with Northeast gas supply reaching 2 Bcf/d it is nearly % selfsufficient during the summertime and requires significantly less imports from the South, Midcon and Canada to meet heating demand during the peak winter months. Exhibit 6: Northeast annual natural gas demand (Bcf/d January through July) Exhibit 7: Northeast seasonal ranges (Bcf/d) year range Source: Bentek Energy, Credit Suisse 7 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Source: Bentek Energy, Credit Suisse It is well documented how growth in the gas power sector has led the lions share in total US gas demand gains over the past decade. And while we think the power sector will continue to be an important driver for the US and Northeast particularly before LNG exports and new manufacturing later this decade cumulative power demand gains in the Northeast are likely to be less than. from 24 through 26, less than many anticipate. Wind additions and negative demand growth from energy efficiency targets (A Thought... Energy Efficiency) outpace coal retirements until 26. Factoring all the moving parts of Northeast power demand, only 4 MMcf/d of gas demand growth is expected through 26. Using A Deep(er) Dive into Gas Demand from the Power Sector as the backbone for the analysis, we conclude that: PJM accounts for the entire 4 MMcf/d of growth as NEISO growth of 42 MMcf/d is offset by 42 MMcf/d of declining demand in NYISO. Coal retirements provide the largest uplift to demand growth in PJM where 269 MMcf/d are due to be discharged. NYISO and NEISO are not anticipated to see any coal retirements through 26. The installation of wind capacity offsets MMcf/d in cumulative demand growth by 26 with 4 MMcf/d located in PJM. NYISO and NEISO see a cumulative uplift in gas demand of 26 MMcf/d in 26 due to risks of nuclear plant retirements, namely the Vermont Yankee and Ginna plants. US Natural Gas Reservoir

11 3 August 23 Exhibit 8: Power gas demand growth by ISO (cumulative starting in 24 in MMcf/d per year) Exhibit 9: Wind additions and efficiency gains restrict power demand growth in the Northeast 6 PJM NYISO NEISO Cumulative Net 8 Gas Additions Wind Additions Nuclear Shifts Demand Increases Coal Retirements Net Gas growth Source: Credit Suisse Source: Credit Suisse NE basis: Permanent dislocation or a short term anomaly? Northeast basis markets are set for a period of sustained weakness As US Northeast supplies have continued their aggressive growth trends, the once Northeast premium market has all but dissipated today. Shown in Exhibit 2, average basis prices from the major NE trading hubs has fallen $.3 YoY from an $. premium to Henry Hub last August to a $.24 discount to Henry hub today. As highlighted above, oversupply and pipeline spec issues stemming from wet-gas production growth in Northwestern PA have led to heavy discounts at Dominion South as well as nearby TCO pricing points. Given the number of pipeline projects adding import capacity to the NJ/NY markets over the next 6-2 months, TETCO M3, Transco Z6 (non-ny) and Transco Z6 NY may be next to see sustained pricing discounts to Henry Hub. New England markets see two minor projects pipeline bringing ~2 MMcf/d of capacity while the recently started 3 MMcf/d Deep Panuke project in Nova Scotia may help reduce occurrences of seasonal basis blowouts at Algonquin City gate. Exhibit 2: Northeast basis prices have considerably weakened ($/MMbtu) $3. $2. $2. $. $. $. $. -$. TETCO M3 Transco Z6 Non-NY Transco Z6 NY Dominion S TCO Algonquin -$. NE Average Apr-2 Jun-2 Aug-2 Oct-2 Dec-2 Feb-3 Apr-3 Jun-3 Aug-3 Source: the BLOOMBERG PROFESSIONAL service, Credit Suisse US Natural Gas Reservoir

12 3 August 23 Backhauls to the rescue? With limited need for historically important Northeast pipeline imports from the Gulf Coast, Midcontinent and the Rockies, a number of physical backhaul pipelines have been announced to alleviate growing supply pressures. The announced projects are unique because they aim to move physical gas along pipes in reverse direction from what typically had been seen, something that has in recent times been done using a financial agreement. We think this indicates a desire by producers to find a permanent solution to what is likely to be acute oversupply in the Northeast gas market. Texas Eastern Transmission Gulf Markets Expansion: Bcf/d from NE to TX and LA, in service 2H 27. Tennessee Gas pipeline s Southwest Louisiana supply project: Bcf/d moves gas to Cameron Interstate Pipeline, the header system for the Cameron LNG terminal in Cameron Parish, Louisiana starting 2H 27. Columbia gas transmission: already backhauls gas from KY to LA to serve storage hubs and growing industrial demand in the Gulf region. Kinder Morgan s Elba Express Pipeline: Held open season to move 6 MMcf/d north to south as well as to its proposed LNG export terminal at the Georgia terminal. Capacity would phase in June 26 and April, 29. The Rockies Express (REX) pipeline announced a physical backhaul agreement in July with an unnamed Utica producer sending 2 MMcf/d of Utica gas to Midcon. An increasing number of Marcellus/Utica producers have voiced desires to turn REX into a bidirectional pipeline. US Natural Gas Reservoir 2

13 3 August 23 Maps and complete project lists: Exhibit 2: Major Interstate Northeast Pipeline Infrastructure Map Source: Energy Velocity, Credit Suisse US Natural Gas Reservoir 3

14 3 August 23 Exhibit 22: Northeast pipeline project list Project Name Pipeline Operator Name Project Type Status Completed Date Year In Service Date Region(s) Additional Capacity (MMcf/d) 2 system expansion Eastern Shore Natural Gas Expansion Completed 22 Northeast 6.2 Cecil County Expansion Eastern Shore Natural Gas Expansion Completed 22 Northeast 4.7 Appalachian Gateway Project Dominion Transmission New Pipeline Completed 9/4/22 22 Northeast Northeast Expansion Project Dominion Transmission Expansion Completed /3/22 22 Northeast 2 Inergy Marc I Hub Line Project Inergy Midstream, LLC Expansion Completed /4/22 22 Northeast TETCO TEAM 22 Expansion Texas Eastern Transmission Expansion Completed /3/22 22 Northeast 2 Bayonne Delivery Lateral Project Transcontinental Gas Pipe Line Lateral Completed 4/4/22 22 Northeast 2 Northern Access Expansion Project National Fuel Gas Supply Corp Expansion Completed /3/22 22 Northeast 32 Line N 22 Expansion National Fuel Gas Supply Corp Expansion Completed /3/22 22 Northeast Philadelphia Lateral Expansion Project Texas Eastern Transmission Expansion Completed /8/22 22 Northeast 27 Station 23C Project Tennessee Gas Pipeline Co Expansion Completed /6/22 22 Northeast 32 Northeast Supply Diversification Project Tennessee Gas Pipeline Co Expansion Completed /9/22 22 Northeast 2 Sunrise Project Equitrans New Pipeline Completed 7/9/22 22 Northeast 33.6 Ellisburg to Craigs Project Dominion Transmission Lateral Completed /3/22 22 Northeast ,39 Hancock compressor project Millennium Pipeline Expansion Approved 23 Northeast 7. Tioga County Extension Phase II Empire Pipeline Expansion Announced 23 Northeast 26 Greenspring Expansion Project Eastern Shore Natural Gas Co Expansion Construction 23 Northeast Northeast Upgrade Project Tennessee Gas Pipeline Co Expansion Construction 23 Northeast 636 Minisink Compressor Project Millennium Pipeline Expansion Completed 23 Northeast 22 NJ-NY Project Spectra Energy Expansion Construction 23 Northeast 8 Mid-Atlantic Connector Expansion Transcontinental Gas Pipe Line Expansion Construction 23 Northeast 42 MPP Project Tennessee Gas Pipeline Co Expansion Approved 23 Northeast 24 Northeast Supply Link Project Transcontinental Gas Pipe Line Expansion Construction 23 Northeast 2 Tioga Area Expansion Project Dominion Transmission Expansion Construction 23 Northeast 27 Sabinsville to Morrisville Project Dominion Transportation Inc Expansion Applied 23 Northeast 92 North-South II Capacity Expansion and Extension Inergy LP Expansion Announced 23 Northeast 32 Line MB extension phase Columbia Gas Transmission Expansion Filed 23 Northeast 23 3,363 Line MB extension phase 2 Columbia Gas Transmission Expansion Filed 24 Northeast Transco power plant link Transcontinental Gas Pipe Line Lateral Announced 24 Northeast Downeast LNG Lateral Downeast LNG LLC Lateral Applied 24 Northeast Iroquois NY Marc Project Iroquois Pipeline Co New Pipeline Announced 24 Northeast Transco Rockaway Delivery Project Transcontinental Gas Pipe Line New Pipeline Pre-Filed 24 Northeast 647 TETCO TEAM 24 Expansion Texas Eastern Transmission Expansion Pre-filed 24 Northeast 6 Northeast Connector WILLIAMS Expansion Announced 24 Northeast VEPCO-Warren County Project Columbia Gas Transmission Expansion Approved 24 Northeast 246 West Side Expansion Project NiSource Gas Transmission & Storage Expansion Announced 24 Northeast 2 Texas Eastern Natrium Lateral Project Texas Eastern Transmission Lateral Announced 24 Northeast ,243 US Natural Gas Reservoir 4

15 3 August 23 Exhibit 23: Marcellus and Utica gas processing additions Source: Markwest, Credit Suisse Exhibit 24: Mariner West Exhibit 2: Mariner East I and II Source: Credit Suisse Source: Credit Suisse US Natural Gas Reservoir

16 3 August 23 Exhibit 26: ATEX Express pipeline Source: Enterprise Products, Credit Suisse US Natural Gas Reservoir 6

17 3 August 23 CS Supply Demand Model and Price Forecast Exhibit 27: US Natural Gas Supply/Demand Model (Bcf/d) (Bcfd) Q/23 Q2/23 Q3/23 Q4/23 23 Q/24 Q2/24 Q3/24 Q4/ Marketed Gas Production Y-o-Y Y-o-Y% 3.4% 7.4%.%.7%.7% 2.%.%.% 2.9% 2.6% 2.7% 3.% 2.8% 3.4% Dry Gas Production Y-o-Y Y-o-Y% 3.3% 7.4% 4.8%.6%.6% 2.%.8%.6% 3.% 2.8% 2.7% 3.% 2.9% 3.4% Conventional Y-o-Y Y-o-Y% -7.4% -2.4%.% -.3% -2.3% -2.7% -2.2% -3.%.7% -.9% -2.% -2.% -.3% -.9% Offshore (GOM) Y-o-Y Y-o-Y% -8.% -8.7% -6.6% -.2% -.2% -.% -.2% -6.8% -.% -9.% -7.7% -6.3% -8.% -.8% Unconventional Y-o-Y Y-o-Y% 24.% 29.9% 2.% 8.8% 7.8% 7.% 6.7% 7.6% 6.% 7.4% 8.2% 8.8% 7.7% 7.9% Barnett Y-o-Y Y-o-Y% 3.% 7.6%.4% -.% -7.2% -7.3% -.2% -6.2% -3.3%.2% 4.% 8.% 2.2% 2.3% Cana-Woodford Y-o-Y Y-o-Y%.3% -4.2% 2.7% -.4% -6.7% -.7% -2.3% -.%.4% 4.3% 4.6% 3.7% 3.% 2.% Eagle Ford Y-o-Y Y-o-Y% 486.% 274.4% 2.6% 8.% 68.6% 2.% 4.% 8.% 29.% 23.7% 2.4% 9.4% 23.2%.8% Fayetteville Y-o-Y Y-o-Y% 48.% 22.7% 6.% 7.6% 2.% -.9% -2.2%.7% -.2% -.% -4.3% -3.% -4.%.2% Haynesville Y-o-Y Y-o-Y% 84.8% 66.8% -2.8% -23.2% -9.9% -3.% -8.% -6.% -3.8%.% 3.6% 4.3%.2% 4.9% Marcellus Y-o-Y Y-o-Y% 29.6% 84.8%.4% 62.7% 48.4% 34.7% 26.% 4.9% 2.4% 8.6% 7.% 6.% 8.% 4.7% Mississippian Y-o-Y Y-o-Y% -.6% -3.8% 2.% 3.% 9.8% 7.6% -.3% 4.9% 2.% 4.9% 6.2% 6.% 4.9%.9% Denver-Julesburg Y-o-Y Y-o-Y%.6%.2% -2.% -4.4% -3.% -.7% -.6% -2.% -9.7% -9.4% -9.2% -8.9% -9.3% -8.% Niobrara Y-o-Y Y-o-Y% #DIV/! 733.3% 274.4% 92.3%.8%.9% 8.3% 4.3% 9.9% 83.% 76.7% 7.2% 79.% 2.% Permian Y-o-Y Y-o-Y% -7.9% -.8% 3.8% 4.% 4.% 3.% 3.6% 3.8% 4.2% 3.% 2.8% 2.8% 3.2% -7.% Granite Wash Y-o-Y Y-o-Y% 6.7% 7.7% -.% 3.8% 2.%.8% -.%.4% -.2% 3.% 3.7% 3.7% 2.6% 2.8% Canadian Imports (Net) Y-o-Y Y-o-Y% -.2% -4.2% -8.9% -7.7% -2.9% -7.2% -3.3% -.7% -7.2% -.% -4.8% -3.% -.3% -.6% Mexican Exports (Net) Y-o-Y Y-o-Y% -2.3% 63.6% 24.% 48.4%.% 26.4% 32.4% 2.2% 2.% 37.2% 3.3% 3.% 34.2% 2.6% LNG Imports (Net) Y-o-Y Y-o-Y% -2.3% -24.4% -47.3% -2.% -3.3% -39.3% -3.% -3.6% -3.% -3.% -3.% -3.% -3.% -74.9% Total Supply Y-o-Y Y-o-Y% 2.7% 4.% 3.% -.%.2% -.%.3% -.%.%.%.%.7%.2%.% Industrial Y-o-Y Y-o-Y%.7%.% 3.%.% 2.%.% 2.7% 2.6% 2.% 3.9% 3.% 3.7% 3.2% 3.% Electric Power Y-o-Y Y-o-Y% 7.% 2.% 2.4% -7.9% -2.% -3.% -2.7% -.7% -7.% -6.7% -.2% -7.3% -6.4% 3.% Res/Comm Y-o-Y Y-o-Y% -.% -.2% -.4% 22.% 4.% -6.7% 9.3% 3.9% -.7% -3.% -.2% -.% -6.% -.3% Other (Lease Fuel, Pipeline Distribution) Y-o-Y Y-o-Y%.8% 2.% 4.7% 3.6%.8% 3.% 3.% 2.6% 3.% 3.% 3.% 3.% 3.% 3.% Total Demand Y-o-Y Y-o-Y%.%.2% 4.2% 8.% -.% -7.% 3.6%.6% -6.2% -.% -.2% -.% -2.8% 2.% Source: Bentek Energy, EIA, HPDI, Credit Suisse Commodities Research US Natural Gas Reservoir 7

18 $3.3 $3.34 $3.46 $3.47 $ $3.74 $3.74 $3.7 $3.6 $3.67 $3.73 $3.74 $3.77 $3.76 $3.78 $3.86 $3.89 $3.89 $3.88 $3.9 $3.93 $3.93 $4.3 $4.2 $4. $4.6 $3.98 $4.3 $ August 23 Pricing Trends and Trading Statistics Exhibit 28: Natural gas futures chart ($/Mmbtu) $4. $4.3 $4. $3.9 $3.7 $3. $3.3 $3. $2.9 FY 23: $3.9 FY 24: $3.76 FY 2: $3.99 $2.7 $2. Source: Credit Suisse, the BLOOMBERG PROFESSIONAL service Exhibit 29: Day ahead gas price by major US trading hub Pricing as of ($/Mmbtu) Source: Energy Velocity, ICE, Credit Suisse US Natural Gas Reservoir 8

19 3 August 23 Exhibit 3: NYMEX Spot, futures, and CS forecast ($/Mmbtu) Exhibit 3: NYMEX futures curve ($/Mmbtu) $. NG Actual NG Quarterly Current Futures Forecast $. $4.8 Current Last week Last month 6 months $4. $4.6 $4. $4.4 $3. $4.2 $4. $3. $3.8 $2. $3.6 $3.4 $2. 2//2 2//22 2//23 2//24 2//2 $3.2 Sep-3 Mar-4 Sep-4 Mar- Sep- Mar-6 Sep-6 Mar-7 Sep-7 Source: Credit Suisse Commodities Research, the BLOOMBERG PROFESSIONAL service Source: Credit Suisse, the BLOOMBERG PROFESSIONAL service Exhibit 32: NYMEX nat gas futures and options: disaggregated CFTC data $6. $. NG MM Net Length (rhs) Producer Net Length (rhs), 4, Exhibit 33: NYMEX nat gas 3-day realized and implied volatilities 4 2 3D Vol Implied Vol $4. $3. $2. 3, 2,, $. -, 2 $. Jan- May- Sep- Jan-2 May-2 Sep-2 Jan-3 May-3-2, Jan-9 Jul-9 Jan- Jul- Jan- Jul- Jan-2 Jul-2 Jan-3 Jul-3 Source: Credit Suisse, the BLOOMBERG PROFESSIONAL service Source: Credit Suisse, the BLOOMBERG PROFESSIONAL service Exhibit 34: US natural gas composite spot prices ($/Mmbtu) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average Q 2Q 3Q 4Q 996 $2.34 $3.27 $2. $2.24 $2.3 $2.2 $2.33 $.96 $.66 $2.6 $2.68 $3.66 $2.4 $2.7 $2.6 $.98 $ $3.46 $2.37 $.72 $.83 $2.3 $2.7 $2.3 $2.24 $2.64 $2.8 $3.8 $2.22 $2.38 $2.2 $.98 $2.3 $ $2.2 $2.2 $2. $2.3 $2.7 $.99 $2.3 $.79 $.78 $.8 $.9 $.64 $.97 $2. $2.2 $.9 $ $.7 $.66 $.64 $.93 $2.4 $2.6 $2.2 $2.62 $2. $2.3 $2.4 $2.38 $2. $.68 $2.8 $2.4 $ $2.26 $2. $2.62 $2.87 $3.26 $4.6 $3.97 $4.3 $4.82 $4.9 $.2 $8.2 $4.7 $2.46 $3.43 $4.3 $6.9 2 $8.72 $.63 $. $. $4. $3.2 $2.96 $2.83 $2.9 $2.28 $2.3 $2.2 $3.88 $6.4 $4.9 $2.63 $ $2.4 $2. $2.74 $3.6 $3.24 $3. $2.92 $2.87 $3.3 $3.69 $3.86 $4.3 $3. $2.33 $3.4 $2.97 $ $. $6.9 $7.4 $4.94 $.48 $.63 $4.87 $4.88 $4.46 $4. $4.33 $.88 $.3 $6.4 $.3 $4.74 $ $.9 $. $.28 $.62 $6.7 $6. $.82 $.37 $4.84 $.97 $.8 $6.8 $.72 $.43 $.97 $.34 $6.2 2 $2.4 $2. $2.74 $3.6 $3.24 $3. $2.92 $2.87 $3.3 $3.69 $3.86 $4.3 $3. $2.33 $3.4 $2.97 $ $. $6.9 $7.4 $4.94 $.48 $.63 $4.87 $4.88 $4.46 $4. $4.33 $.88 $.3 $6.4 $.3 $4.74 $ $.9 $. $.28 $.62 $6.7 $6. $.82 $.37 $4.84 $.97 $.8 $6.8 $.72 $.43 $.97 $.34 $ $7.83 $8.3 $9.3 $9.86 $.47 $.97 $.8 $7.83 $6.7 $.87 $6. $.6 $8.36 $8.39 $.77 $8.46 $ $4.96 $4.22 $3.64 $3.32 $3.8 $3.7 $3.3 $3.2 $2.86 $3.93 $3.7 $.27 $3.78 $4.27 $3.49 $3.9 $ $.8 $.3 $4.28 $3.94 $4. $4.66 $4.3 $4.2 $3.8 $3.39 $3.64 $4.24 $4.33 $. $4.22 $4.8 $ $4.42 $4.23 $3.93 $4. $4.2 $4. $4.38 $4.4 $3.84 $3.46 $3.2 $3.8 $3.97 $4.9 $4.3 $4.9 $ $2.6 $2.48 $2. $.92 $2.3 $2.4 $2.9 $2.82 $2.77 $3.27 $3. $3.29 $2.7 $2.4 $2.22 $2.83 $ $3.3 $3.29 $3.74 $4.2 $3.97 $3.73 $3. $3.68 $3.44 $3.97 $3. Avg $4.22 $4.9 $4.4 $3.9 $4. $4.2 $4. $3.7 $3. $3.8 $3.86 $4.44 $4. $4. $4. $3.77 $4.3 High $8.72 $8.3 $9.3 $9.86 $.47 $.97 $.8 $7.83 $6.7 $.97 $6. $8.2 $8.36 $8.39 $.77 $8.46 $6.2 Low $.7 $.66 $.64 $.83 $2.3 $.99 $2.3 $.79 $.66 $.8 $.9 $.64 $.97 $.68 $.98 $.9 $.8 Source: Natural Gas Week, Credit Suisse US Natural Gas Reservoir 9

20 Feb-6 Jun-6 Oct-6 Feb-7 Jun-7 Oct-7 Feb-8 Jun-8 Oct-8 Feb-9 Jun-9 Oct-9 Feb- Jun- Oct- Feb- Jun- Oct- Feb-2 Jun-2 Oct-2 Feb-3 Jun-3 Feb-6 Jun-6 Oct-6 Feb-7 Jun-7 Oct-7 Feb-8 Jun-8 Oct-8 Feb-9 Jun-9 Oct-9 Feb- Jun- Oct- Feb- Jun- Oct- Feb-2 Jun-2 Oct-2 Feb-3 Jun-3 Feb-6 Jun-6 Oct-6 Feb-7 Jun-7 Oct-7 Feb-8 Jun-8 Oct-8 Feb-9 Jun-9 Oct-9 Feb- Jun- Oct- Feb- Jun- Oct- Feb-2 Jun-2 Oct-2 Feb-3 Jun-3 Feb-6 Jun-6 Oct-6 Feb-7 Jun-7 Oct-7 Feb-8 Jun-8 Oct-8 Feb-9 Jun-9 Oct-9 Feb- Jun- Oct- Feb- Jun- Oct- Feb-2 Jun-2 Oct-2 Feb-3 Jun-3 3 August 23 Exhibit 3: Henry Hub bid-week natural gas prices ($/Mmbtu) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average Q 2Q 3Q 4Q 996 $2.92 $4.4 $3. $2.7 $2.2 $2.43 $2.7 $2.2 $.84 $2.27 $2.82 $3.78 $2.76 $3.44 $2.4 $2.8 $ $3.47 $2. $.88 $2. $2.9 $2.2 $2.7 $2.4 $2.8 $3.3 $3.23 $2.37 $2.3 $2.63 $2.3 $2.46 $ $2. $2.7 $2.23 $2.4 $2.8 $2.4 $2.2 $.9 $.9 $.93 $2.6 $.69 $2.8 $2.7 $2.26 $2.2 $ $.87 $.78 $.78 $2.7 $2.27 $2.3 $2.23 $2.74 $2.63 $2.63 $2.4 $2.36 $2.27 $.8 $2.2 $2.3 $2. 2 $2.37 $2.66 $2.7 $2.99 $3.47 $4.3 $4. $4.3 $. $. $.2 $8.8 $4.23 $2.9 $3.9 $4.49 $ $9.3 $.73 $.2 $.23 $4.8 $3.78 $3.8 $3. $2.24 $2.44 $2.4 $2.33 $4.7 $6.66 $4.4 $2.8 $ $2.29 $2.26 $2.8 $3.44 $3.4 $3.23 $3.6 $3. $3.4 $4.6 $4.9 $4.6 $3.2 $2.47 $3.4 $3.9 $ $.3 $7.3 $8.6 $.27 $.78 $.84 $.4 $. $4.62 $4.63 $4.46 $6.4 $.63 $6.9 $.63 $4.89 $.8 24 $6.9 $.37 $.36 $.7 $6.29 $6.2 $.94 $.49 $4.9 $6.22 $.89 $6.64 $.8 $.6 $6.8 $.46 $6.2 2 $6.3 $6. $6.96 $7.28 $6.48 $7.9 $7.6 $9.29 $.73 $3.36 $.36 $3.8 $8.79 $6.4 $6.9 $9.3 $ $9.92 $8.4 $7.39 $7.9 $7.3 $.93 $.89 $7.4 $6.82 $4.2 $7.6 $8.34 $7. $8.7 $6.68 $6.8 $ $.84 $6.92 $7. $7.6 $7. $7.9 $6.93 $6. $.43 $6.43 $7.28 $7.2 $6.86 $6.77 $7. $6.6 $ $7.3 $7.99 $8.93 $9.8 $.29 $.93 $3. $9.23 $8.4 $7.48 $6.47 $6.9 $9.4 $8.2 $.93 $.2 $ $6.3 $4.49 $4.7 $3.63 $3.32 $3.4 $3.96 $3.38 $2.83 $3.72 $4.28 $4.49 $3.99 $4.9 $3. $3.39 $4.6 2 $.82 $.28 $4.8 $3.84 $4.27 $4.6 $4.72 $4.78 $3.64 $3.84 $3.29 $4.27 $4.39 $.3 $4.9 $4.38 $3.8 2 $4.22 $4.32 $3.79 $4.24 $4.38 $4.33 $4.36 $4.37 $3.8 $3.76 $3.2 $3.37 $4.4 $4. $4.32 $4.9 $3. 22 $3.8 $2.67 $2.44 $2.9 $2.3 $2.42 $2.77 $3. $2.63 $3.3 $3.47 $3.7 $2.79 $2.73 $2.2 $2.8 $ $3.3 $3.23 $3.43 $3.98 $4.6 $4. $3.7 $3.4 $3.68 $3.34 $4. $3.8 Avg $4.84 $4.6 $4.8 $4. $4.9 $4.6 $4.64 $4.49 $4.4 $4.6 $4.64 $.26 $4.63 $4.69 $4.8 $4.49 $4.82 High $9.92 $8.4 $8.93 $9.8 $.29 $.93 $3. $9.29 $.73 $3.36 $.36 $3.8 $9.4 $8.7 $.93 $.2 $2.27 Low $.87 $.78 $.78 $2. $2.3 $2.4 $2.7 $.9 $.84 $.93 $2.6 $.69 $2.8 $.8 $2.3 $2.2 $.89 Source: Natural Gas Week, Credit Suisse Exhibit 36: Henry Hub differential Henry Hub vs. NYMEX Differential Exhibit 37: Mid-continent differential Mid-Continent vs. NYMEX Differential $. Henry Hub - NYMEX Differential Average $2. Mid-Continent - NYMEX Differential Average $.4 $.3 $.2 3Q3 QTD Avg. Price differential $. vs. -$.2 LTA $. $. $. $. ($.) ($.2) ($.3) ($.4) ($.) ($2.) ($3.) ($4.) 3Q3 QTD Avg. Price differential -$.6 vs. -$.64 LTA Source: Natural Gas Week, Credit Suisse Source: Natural Gas Week, Credit Suisse Exhibit 38: South Texas differential South Texas vs. NYMEX Differential Exhibit 39: AECO differential AECO vs. NYMEX Differential $.4 $.2 South Texas - NYMEX Differential Average $. $. AECO - NYMEX Differential Average $. $. ($.2) ($.) ($.4) ($.6) ($.8) ($.) 3Q3 QTD Avg. Price differential -$.6 vs. -$.28 LTA ($.) ($.) ($2.) 3Q3 QTD Avg. Price differential -$.86 vs. -$.7 LTA ($.2) ($2.) Source: Natural Gas Week, Credit Suisse Source: Natural Gas Week, Credit Suisse US Natural Gas Reservoir 2

21 Feb-6 Jun-6 Oct-6 Feb-7 Jun-7 Oct-7 Feb-8 Jun-8 Oct-8 Feb-9 Jun-9 Oct-9 Feb- Jun- Oct- Feb- Jun- Oct- Feb-2 Jun-2 Oct-2 Feb-3 Jun-3 Feb-6 Jun-6 Oct-6 Feb-7 Jun-7 Oct-7 Feb-8 Jun-8 Oct-8 Feb-9 Jun-9 Oct-9 Feb- Jun- Oct- Feb- Jun- Oct- Feb-2 Jun-2 Oct-2 Feb-3 Jun-3 Feb-6 Jun-6 Oct-6 Feb-7 Jun-7 Oct-7 Feb-8 Jun-8 Oct-8 Feb-9 Jun-9 Oct-9 Feb- Jun- Oct- Feb- Jun- Oct- Feb-2 Jun-2 Oct-2 Feb-3 Jun-3 Feb-6 Jun-6 Oct-6 Feb-7 Jun-7 Oct-7 Feb-8 Jun-8 Oct-8 Feb-9 Jun-9 Oct-9 Feb- Jun- Oct- Feb- Jun- Oct- Feb-2 Jun-2 Oct-2 Feb-3 Jun-3 3 August 23 Exhibit 4: Waha differential $. $. $. $. ($.) ($.) ($.) ($2.) ($2.) ($3.) ($3.) Waha vs. NYMEX Differential Waha - NYMEX Differential Average 3Q3 QTD Avg. Price differential -$.7 vs. -$.49 LTA Exhibit 4: Carthage differential $.6 $.4 $.2 $. ($.2) ($.4) ($.6) ($.8) ($.) ($.2) ($.4) Carthage vs. NYMEX Differential Carthage - NYMEX Differential Average 3Q3 QTD Avg. Price differential -$.6 vs. -$.29 LTA Source: Natural Gas Week, Credit Suisse Source: Natural Gas Week, Credit Suisse Exhibit 42: East Texas differential East Texas vs. NYMEX Differential Exhibit 43: Appalachia differential Appalachia vs. NYMEX Differential $. $. $. ($.) ($.) ($.) East Texas - NYMEX Differential Average 3Q3 QTD Avg. Price differential -$.6 vs. -$.34 LTA $. $.8 $.6 $.4 $.2 $. ($.2) Appalachia - NYMEX Differential Average 3Q3 QTD Avg. Price differential -$.2 vs. $.8 LTA ($2.) ($.4) Source: Natural Gas Week, Credit Suisse Source: Natural Gas Week, Credit Suisse US Natural Gas Reservoir 2

22 Jan-8 Mar-8 May-8 Jul-8 Sep-8 Nov-8 Jan-9 Mar-9 May-9 Jul-9 Sep-9 Nov-9 Jan- Mar- May- Jul- Sep- Nov- Jan- Mar- May- Jul- Sep- Nov- Jan-2 Mar-2 May-2 Jul-2 Sep-2 Nov-2 Jan-3 Mar-3 May Jan-8 Mar-8 May-8 Jul-8 Sep-8 Nov-8 Jan-9 Mar-9 May-9 Jul-9 Sep-9 Nov-9 Jan- Mar- May- Jul- Sep- Nov- Jan- Mar- May- Jul- Sep- Nov- Jan-2 Mar-2 May-2 Jul-2 Sep-2 Nov-2 Jan-3 Mar-3 May-3 Jul-3 (3.) (.) (.7) (.) (.3) (.2) (.4) Jan-8 Mar-8 May-8 Jul-8 Sep-8 Nov-8 Jan-9 Mar-9 May-9 Jul-9 Sep-9 Nov-9 Jan- Mar- May- Jul- Sep- Nov- Jan- Mar- May- Jul- Sep- Nov- Jan-2 Mar-2 May-2 Jul-2 Sep-2 Nov-2 Jan-3 Mar-3 May-3 Jul August 23 Supply Exhibit 44: US dry gas production (indicated by pipeline scrapes) (Bcf/d) Dry Gas Production Source: Bentek Energy, Credit Suisse Exhibit 4: Year-over-year US dry gas production (indicated by pipeline scrapes) (Bcf/d) Y-o-Y Dry Gas Production () (2) (3) (4) Source: Bentek Energy, Credit Suisse Exhibit 46: US lower 48 natural gas production U.S. Low er 48 Natural Gas Production (Bcf/d) US Natural Gas Reservoir 22

23 Jan Jan-8 Feb-8 Mar-8 Apr-8 May-8 Jun-8 Jul-8 Aug-8 Sep-8 Oct-8 Nov-8 Dec-8 Jan-9 Feb-9 Mar-9 Apr-9 May-9 Jun-9 Jul-9 Aug-9 Sep-9 Oct-9 Nov-9 Dec-9 Jan- Feb- Mar- Apr- May- Jun- Jul- Aug- Sep- Oct- Nov- Dec- Jan- Feb- Mar- Apr- May- Jun- Jul- Aug- Sep- Oct- Nov- Dec- Jan-2 Feb-2 Mar-2 Apr-2 May-2 Jun-2 Jul-2 Aug-2 Sep-2 Oct-2 Nov-2 Dec-2 Jan-3 Feb-3 Mar-3 Apr-3 May Mar-8 May-8 Jul-8 Sep-8 Nov-8 Jan-9 Mar-9 May-9 Jul-9 Sep-9 Nov-9 Jan- Mar- May- Jul- Sep- Nov- Jan- Mar- May- Jul- Sep- Nov- Jan-2 Mar-2 May-2 Jul-2 Sep-2 Nov-2 Jan-3 Mar-3 May Jan-8 Mar-8 May-8 Jul-8 Sep-8 Nov-8 Jan-9 Mar-9 May-9 Jul-9 Sep-9 Nov-9 Jan- Mar- May- Jul- Sep- Nov- Jan- Mar- May- Jul- Sep- Nov- Jan-2 Mar-2 May-2 Jul-2 Sep-2 Nov-2 Jan-3 Mar-3 May-3 3 August 23 Exhibit 47: Onshore natural gas production Onshore Natural Gas Production (Bcf/d) Exhibit 48: Offshore natural gas production Offshore Natural Gas Production (Bcf/d) Exhibit 49: Year-over-year change in US lower 48 natural gas production YoY Change in U.S. Low er 48 Natural Gas Production (Bcf/d) US Natural Gas Reservoir 23

24 Jan-8 Feb-8 Mar-8 Apr-8 May-8 Jun-8 Jul-8 Aug-8 Sep-8 Oct-8 Nov-8 Dec-8 Jan-9 Feb-9 Mar-9 Apr-9 May-9 Jun-9 Jul-9 Aug-9 Sep-9 Oct-9 Nov-9 Dec-9 Jan- Feb- Mar- Apr- May- Jun- Jul- Aug- Sep- Oct- Nov- Dec- Jan- Feb- Mar- Apr- May- Jun- Jul- Aug- Sep- Oct- Nov- Dec- Jan-2 Feb-2 Mar-2 Apr-2 May-2 Jun-2 Jul-2 Aug-2 Sep-2 Oct-2 Nov-2 Dec-2 Jan-3 Feb-3 Mar-3 Apr-3 May Jan-8 Feb-8 Mar-8 Apr-8 May-8 Jun-8 Jul-8 Aug-8 Sep-8 Oct-8 Nov-8 Dec-8 Jan-9 Feb-9 Mar-9 Apr-9 May-9 Jun-9 Jul-9 Aug-9 Sep-9 Oct-9 Nov-9 Dec-9 Jan- Feb- Mar- Apr- May- Jun- Jul- Aug- Sep- Oct- Nov- Dec- Jan- Feb- Mar- Apr- May- Jun- Jul- Aug- Sep- Oct- Nov- Dec- Jan-2 Feb-2 Mar-2 Apr-2 May-2 Jun-2 Jul-2 Aug-2 Sep-2 Oct-2 Nov-2 Dec-2 Jan-3 Feb-3 Mar-3 Apr-3 May August 23 Exhibit : Year-over-year change in onshore natural gas production YoY Change in Onshore Natural Gas Production (Bcf/d) Exhibit : Year-over-year change in offshore natural gas production YoY Change in Offshore Natural Gas Production (Bcf/d) US Natural Gas Reservoir 24

25 Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- Jan-2 Apr-2 Jul-2 Oct-2 Jan-3 Apr-3 Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- Jan-2 Apr-2 Jul-2 Oct-2 Jan-3 Apr-3 Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- Jan-2 Apr-2 Jul-2 Oct-2 Jan-3 Apr-3 Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- Jan-2 Apr-2 Jul-2 Oct-2 Jan-3 Apr-3 Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- Jan-2 Apr-2 Jul-2 Oct-2 Jan-3 Apr-3 Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- Jan-2 Apr-2 Jul-2 Oct-2 Jan-3 Apr-3 3 August 23 Exhibit 2: Texas natural gas production Texas Natural Gas Production (Bcf/d) As of May 23 Up.% YTD (+. Bcf/d) Up.7% Yr/Yr (+. Bcf/d) Exhibit 3: Louisiana natural gas production Louisiana Natural Gas Production (Bcf/d) As of May 23 Down 6.% YTD (-.3 Bcf/d) Down 9.6% Yr/Yr (-.63 Bcf/d) Exhibit 4: Oklahoma natural gas production Oklahoma Natural Gas Production (Bcf/d) As of May 23 Up 6.6% YTD (+.3 Bcf/d) Up.8% Yr/Yr (+.32 Bcf/d) Exhibit : New Mexico natural gas production New Mexico Natural Gas Production (Bcf/d) As of May 23 Down 4.% YTD (-. Bcf/d) Down.% Yr/Yr (+. Bcf/d) Exhibit 6: Wyoming natural gas production Wyoming Natural Gas Production (Bcf/d) Exhibit 7: Other states natural gas production Other States Natural Gas Production (Bcf/d) 8 As of May 23 Down 9.6% YTD (-.62 Bcf/d) Down 9.% Yr/Yr (-.6 Bcf/d) 2 2 As of May 23 Up 3.8% YTD (+3.3 Bcf/d) Up 4.% Yr/Yr (+3.4 Bcf/d) US Natural Gas Reservoir 2

26 Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- Jan-2 Apr-2 Jul-2 Oct-2 Jan-3 Apr-3 Jul-3 Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- Jan-2 Apr-2 Jul-2 Oct-2 Jan-3 Apr-3 Jul-3 Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- Jan-2 Apr-2 Jul-2 Oct-2 Jan-3 Apr-3 Jul-3 Jan-8 Apr-8 Jul-8 Oct-8 Jan-9 Apr-9 Jul-9 Oct-9 Jan- Apr- Jul- Oct- Jan- Apr- Jul- Oct- Jan-2 Apr-2 Jul-2 Oct-2 Jan-3 Apr-3 Jul-3 3 August 23 US Imports/Exports Exhibit 8: Monthly net natural gas imports (Bcf/d) Net Imports Exhibit 9: Monthly imports from Canada (Bcf/d) Canadian Imports 9 8 As of August 23 Down 2.3% YTD (-.9 Bcf/d) Down 32.6% Yr/Yr (-.49 Bcf/d) As of August 23 Down 8.% YTD (-.44 Bcf/d) Down 8.2% Yr/Yr (-.7 Bcf/d) Source: Bentek Energy, Credit Suisse Source: Bentek Energy, Credit Suisse Exhibit 6: Monthly LNG imports (Bcf/d) LNG Imports Exhibit 6: Monthly Mexican exports (Bcf/d) Mexican Exports As of August 23 Down 37.% YTD (-.9 Bcf/d) Down 39.% Yr/Yr (-.9 Bcf/d) - (.2). (.4) (.6). (.8) (.). (.2) (.4) - (.6) (.8) (2.) As of August 23 Up 9.% YTD (+.28 Bcf/d) Up 2.8% Yr/Yr (+.23 Bcf/d) Source: Bentek Energy, Credit Suisse Source: Bentek Energy, Credit Suisse US Natural Gas Reservoir 26