Anticipating Changes in US Natural Gas Production and Prices New York Energy Forum November 1, 2010 Ron Denhardt Chief Executive Officer, SEER Vice President, Lippman Consulting Inc. RonDenhardt@EnergySEER.com 781 756 0550

A Brief Commercial Message SEER provides a complete energy forecasting service. Our products include short term monthly outlooks and long term scenarios. SEER has made many correct calls that have been sharply different from the forward market. Lippman Consulting Inc. (LCI) provides daily natural gas pipeline flow data that estimates natural gas production, imports, and natural gas consumption. LCI also provides natural gas production models that model over 100 types by vintage. LCI’s new monthly shale model provides a valuable tool for estimating the impact of a changing rig count on natural gas production from shale.

A deep recession and a surge in production have driven natural gas prices below the level reached in the 2001-02 recession.

Will they be right this time? Low prices are expected to continue as a result of optimism about natural gas production from shale. Once again the view of the natural gas future has shifted radically. Until 2000 natural gas costs were low because excess reserves and production capacity was developed in the 70s and 80s. There was great optimism about supply. However, increased utilization of natural productive capacity and declining reserves were signaling a tightening market. For the first time in over a decade the industry had to develop gas supply from new exploration. In 2000 prices jumped sharply but production did not respond. Analysts then decided the US would have to import large volumes of LNG and gas price forecasts were increased sharply. Many of the same players who were wrong in the 1990s and the last seven or eight years now claim the huge low cost shale resource base will assure low prices for decades and that the US will not need LNG imports. Cheniere has received approval to export LNG using domestically produced gas. Will they be right this time? From Chesapeake Energy “Investment community short natural gas (in fact, hates natural gas now and forever)”

There are seven major North American shale plays – Barnett, Haynesville, Fayetteville, Woodford and Marcellus in the US and Horn River and Montney in Canada. Also, Eagle Ford is now hot because of liquids content.

Source: Lippman Consulting Inc. Natural gas production from shale increased 2.85 Bcfd in 2009. The projected increase in production in 2010 is about 4 Bcfd and in 3.3 Bcfd in 2011. Source: Lippman Consulting Inc.

Attractive economics, joint ventures and a rush to purchase land, HBP provisions are driving shale production. $16 billion of funding raised during the last year through acreage joint ventures Many joint ventures make much of the cost of developing natural gas production from shale a sunk cost. High prices for acreage $10,000 to $30,000 in Haynesville and upfront bonuses add to the sunk cost. Hold By Production (HBP) provisions specify a three-year time frame to drill and begin production with a 25% royalty for each section, which is typically defined by 640 acres. But, because of low prices, many producers are claiming they will only develop reserves required by JVs and HBP until prices increase to $6.00 per MMBtu. The strategy is to shift to drilling rich gas and oil but the ethane market is limited by chemical production.

Monthly Natural Gas from Shale Production Model Horizontal Rigs by County Rig Efficiency Lag to Delivery Wells First Delivered Production Profiles Monthly Production Existing Production by Vintage Permits Economics Note annual model does 100 types (shale, coal seam, deep, shallow, location) in similar format.

Low prices are slowing the growth of the horizontal rig count but liquids rich Eagle Ford is growing rapidly and Marcellus continues to grow. Haynesville Marcellus Eagle Ford Source: LCI

First year decline rates in the sample below were 60% for Barnett and 87% for Haynesville. We are modeling 80% Haynesville.

Based on the projected rig count, natural gas production from shale will increase about 3.3 Bcfd but the monthly growth in production will decline during the year. Note the early months are locked in by past drilling.

Other than Haynesville in Louisiana, low prices have not slowed down permits.

Sharp declines in non-shale production will be required to offset a loose supply-demand balance. Weather adjusted storage injections suggests the market is 2-3 Bcfd looser than last year. LCI and Bentek show September Year over Year production growth of 6% to 7% or about 4-4.5 Bcfd. With demand growth 2-3 Bcfd, production growth explains the looser supply-demand balance. Weather adjusted storage injections indicate storage would end March at a record of 1,900 Bcf and our full supply demand balance at 1,700 Bcf with a 500 Bcf swing from heating degree days 10% above or below normal.

Data is adjusted for hurricanes The gas rig count will have to average about 750 during the next 12 months to keep production from growing. Given the lag between drilling and the delivery of gas, the rig count will have to decline quickly or drop well below 750. Non shale production declined 4.3 Bcfd from Feb 2009 to February 2010. The average annual decline was 2.9 Bcfd. The gas rig count averaged 750. At least half of the decline occurred in the Gulf onshore (2.1 Bcfd) and Mid-continent (.7) Bcfd with the other areas declining .2 to .3 Bcfd each. Henry Hub prices averaged about $4 per MMBtu during this period and $3.50 per MMBtu excluding the winter. Rigs are more productive now and HBR may require lower prices this time. Data is adjusted for hurricanes

GOM production would decline .6 Bcfd in 2011 with current rig count

Price forecasts range from 15% below NYMEX to 20% above. The low price argument is based on rapid technological advancement, slow economic growth, sunk costs, and attractive resources. Higher price arguments: Full cycle cost of conventional supplies EPA review, taxes, water, and limited access could raise costs. The impact of the Clean Air Mercury Rule (CAMR) which could cause 15-20% of coal fired plants to be shut-down. Costs under and decline rates are understated, Expected Ultimate Recovery (EUR) is over stated.

Closing Thoughts Near term natural gas prices are likely to stay below equilibrium prices because of sunk costs of both conventional and un-conventional production. Even when HBR is no longer an issue, it will be hard for companies to tell stock holders that we are going to sit on the land that has been purchased and not use it. Low prices could lead to over optimism about long term supply and cause poor investment decisions. There is little question that natural gas shale has changed the game but the track record of long term projections and scenarios is abysmal. There could be substantial value in developing early warning signals of market changes via rigorous models when appropriate and less detailed approaches when the data will not support detailed modeling.