From the Piceance Basin to the Pacific Rim

Transcription

1 From the Piceance Basin to the Pacific Rim How Expanded U.S. LNG Exports Could be critical to the Development of Natural Gas Reserves in Western Colorado s Piceance Basin Presented By 1

2 From the Picence Basin to the Pacific Rim How Expanded U.S. LNG Exports Could be critical to the Development of Natural Gas Reserves in Western Colorado s Piceance Basin AUTHOR S NOTE by John Harpole Author s Note... 1 Introduction... 1 U.S and Piceance Basin Production and Reserves... 5 Williams Fork... 6 Deep Mancos Shale... 7 Long Term Transactions in the Piceance... 8 Midstream Infrastructure Natural Gas Pipeline Transportation out of Western Colorado Natural Gas Pipeline Transportation out of the Rockies Rockies Express Pipeline 17 Ruby Pipeline LNG Exports Conclusion Every effort has been made to make this a plain spoken white paper. It is designed to appeal to the average person on the street (from Grand Junction, Colo., to the potential LNG purchaser in Asia), not just industry experts. The most difficult challenge for a non-natural gas industry reader will be the constant use of a variety of measurements related to natural gas, plus the scale and meaning of that measurement [i.e., MCF (thousand cubic feet), BCF (billion cubic feet), TCF (trillion cubic feet), MMBtu (million British thermal units), cubic meters (m 3 )]. In an effort to assist the reader, the first exhibit in the Appendix presents a comparison of those measurements discussed in this white paper. They will help the reader better understand the scale of natural gas from the producing wellhead to its final point of consumption. I would encourage you to review that two-page Appendix on scale prior to reviewing this analysis. INTRODUCTION Thanks to the combination of hydraulic fracturing and horizontal drilling in shale formations, the U.S. is experiencing an energy revolution. According to a story in the Seattle Times on June 29, 2014, Last fall, Wallace Tyner, an energy economist at Purdue University, estimated in a study that the shale revolution was adding some $473 billion per year to the U.S. economy, or about 3 percent of the gross domestic product. Energy consulting firm IHS recently estimated that more than 2.1 million jobs in the U.S. are now supported by shale-related oil and gas activity. That Shale Revolution has not gone unnoticed by the rest of the world. Emerging world demand for liquefied natural gas may likewise increase demand and create new markets for western Colorado Piceance Basin production. That is especially true for a Buyer of natural gas that is looking for price security and marketability over a 20-year time frame.

3 What is liquefied natural gas (LNG)? When natural gas is cooled to a temperature of approximately -256 degrees Fahrenheit (-161 degrees centigrade), it condenses into a liquid form. By freezing natural gas, you reduce its size 600 times, enough so that an average LNG ship can hold 3 BCF of gas. That is enough natural gas to heat 40,000 homes for one year. The LNG delivery chain includes exploration and production, liquefaction, shipping and storage and regasification (warming the liquid natural gas up and converting it into a gaseous state). Exhibit A illustrates the components of the LNG delivery chain. Exhibit A The LNG Delivery Chain Source: King & Spalding Energy Newsletter, August 2014 This analysis will describe the unique attributes of the Piceance Basin and explain why its reserves are best suited for worldwide liquefied natural gas (LNG) purchasers who want to integrate vertically, from the production wellhead to their final burnertip. By acquiring Piceance Basin reserves, those long-term purchasers of gas can eliminate or, at the very least, minimize the price uncertainty of natural gas. According to the Energy Information Administration (EIA), the U.S. is now the world s No. 1 producer of natural gas. Seven years ago, due to a projected shortfall of natural gas supply, most experts projected the need to import LNG into the U.S. to meet growing demand. Those experts expected that at least 20 percent of U.S. demand would be met by foreign imports through the early part of this century. The need for LNG imports into the U.S. was the accepted assumption until the U.S. Shale Revolution became a reality. Historically, producers of natural gas in the lower 48 states and Canada could only access and satisfy demand on this continent. The super abundance of natural gas in North America now requires producers to reach beyond North American shores to access worldwide markets. According to Bentek Energy, the Shale Gas Revolution should cause U.S. natural gas production to increase by 23 percent from its current annual average level of 65 BCF/day, up to nearly 80 BCF/day by While most experts generally agree on the trend line showing increase in production, the wild card in the mix appears to be connected to the demand side of the equation. Five sectors need to be analyzed in any study of demand growth in the U.S. They are 1) Power - Coal to Gas fuel switching in utility power generation, 2) Industrial Demand i.e., new steel plants, chemical! 2

4 plants, etc., 3) CNG/LNG Vehicles, 4) LNG Exports and 5) Mexico Exports U.S. pipeline deliveries to Mexico. A new supply/demand equilibrium for U.S. natural gas production can be met only through significant U.S. LNG exports. The current estimate of new natural gas demand related to new ammonia, urea and nitrogen chemical plants across the U.S. ($80-$100 billion of new capital investment) is approximately 1.4 BCF/day. While that volume is critical to the demand equation for U.S. gas producers, it is only half the volume that Cheniere Energy plans to export out of their Sabine Pass facility on a daily basis. Of all the demand components listed in Exhibit B, the most critical sector for significant growth relates to LNG exports. Three different forecasts, low, mid and high are shown in Exhibit B. Exhibit B - North American Natural Gas Demand Ranges by Selected Sector Significant demand growth is possible in the LNG, transportation/hhp and power sectors through 2020 in Bcf per day. Power LNG Export Transport/HHP Industrial (U.S. and Oil Sands) Mexico Exports Lower Demand Range Middle Demand Range Upper Demand Range Source: Encana Corporate Presentation, August 2013 An expansion of U.S. LNG export capacity requires a significant financial commitment for actual construction. That opportunity to export U.S. natural gas production to overseas buyers is seen by many economists as a potential economic windfall for the entire U.S. economy. Some of the new natural gas shale plays are experiencing growing pains due to a need more immediate than LNG export capacity. Inadequate midstream pipeline infrastructure is creating severe price discounts for the value of natural gas production in some shale natural gas producing regions of the U.S. Many of the new shale plays have been discovered in areas where there was no existing historical natural gas production and, correspondingly, where there is no existing natural gas pipeline infrastructure.! 3

5 As an example, in the Marcellus Shale play of eastern Pennsylvania, five different index price points (index price points report the value of natural gas in a specific area at a specific time, i.e., daily/ monthly) are trading at a severe discount to their historical values. Discounts are currently ranging from $1.50-$2.50 per MMBtu below the NYMEX Henry Hub Erath, La., price, thanks to an over-abundance of new natural gas production and a lack of natural gas pipeline takeaway capacity. The Piceance Basin of western Colorado is essentially immune to that discounting phenomenon. In fact, the price differential between the Rockies natural gas producing areas and the critical pricing point for all natural gas in the U.S., the NYMEX Henry Hub contract (where physical deliveries are accounted for in Erath, La.) have never been more predictable in the last 15 years. The Northwest-Rockies basis differential has been as high as a negative $6.50 MMBtu (when NYMEX natural gas prices reached $11.00 MMBtu). It averaged a negative $2.12 MMBtu (as compared to the NYMEX price) from August 2005 through January See Exhibit C. Exhibit C Basis Differential Between Northwest-Rockies and NYMEX per MMBtu $0.00 -$1.00 -$2.00 -$3.00 -$4.00 -$5.00 -$6.00 -$7.00 Aug-05 Nov-05 Feb-06 May-06 Aug-06 Nov-06 Feb-07 May-07 Aug-07 Nov-07 Feb-08 May-08 Aug-08 Nov-08 Feb-09 May-09 Aug-09 Nov-09 NW Rockies vs. NYMEX Source: Inside FERC s Gas Marketing Report, A McGraw Hill Publication Piceance Basin producers currently enjoy extensive and under-utilized natural gas pipeline and natural gas processing capacity. That capacity allows Piceance Basin producers unrestricted access to markets from the west coast of the U.S. to the Mid-Atlantic States.! 4

6 That existing midstream infrastructure capacity combined with an abundant gas resource has made the Piceance Basin an attractive area for investment in long-life natural gas reserves. In this analysis, we will explore three critical competitive advantages of the Piceance Basin: proved reserves, potential reserves, and midstream infrastructure (natural gas processing and pipeline export capacity). Additionally, two specific instances of industrial end-user investments in Piceance Basin natural gas reserves will be analyzed. Those investments can serve as a model for the type of upstream production investment that an overseas purchaser of natural gas could mimic in an effort to combine predictably priced, long-life natural gas reserves with U.S. LNG export capacity. U.S. AND PICEANCE BASIN PRODUCTION AND RESERVES In April 2013, the Potential Gas Committee (PGC) increased its estimate of the amount of natural gas reserves in the U.S. to almost five times its prior estimate of 486 trillion cubic feet (TCF). The PGC now estimates that the U.S. has 2,384 TCF of technically recoverable natural gas. That figure gains significance when considered in light of the 26 TCF that the U.S. consumed in By all accounts, the U.S. has at least 100 years of natural gas supply. That figure does not take into consideration potential innovation and advancements in technology. The PGC s year-end 2012 assessment reaffirms the committee s conviction that abundant, recoverable natural gas resources exist within our borders, both onshore and offshore, and in all types of reservoirs from conventional, tight and shales, to coals, said John B. Curtis, professor of geology and geological engineering at the Colorado School of Mines and director of the Potential Gas Agency, which also advises the PGC. He added, Our knowledge of the geological endowment of technically recoverable gas continues to improve with each assessment. Furthermore, new and advanced exploration, well drilling, completion and stimulation technologies are allowing us increasingly better delineation of and access to domestic gas resources especially unconventional gas which, not all that long ago, were considered impractical or uneconomical to pursue. That technological prowess is especially true in Colorado s Piceance Basin. Rarely does any operator drill a Williams Fork dry-hole these days, now that the field boundaries have been fully delineated. I can t think of the last time we drilled a dry-hole. We are developing our reserve based on 10-acre spacing, says Alan Harrison, Vice President of Drilling Operations at WPX Energy, and based on current wellhead economics, we have approximately 10,000 Williams Fork locations remaining. According to the Potential Gas Committee, the Piceance, Eagle Ford and Park Basins of western Colorado have approximately 42 TCF of technically recoverable resources net of produced reserves as of Dec. 31, The Piceance Basin is one of the more mature producing basins in the U.S., with an interesting mixture of vintage natural gas production out of the Williams Fork formation (lower member of the Mesa Verde! 5

7 formation) and new natural gas production out of the Mancos Niobrara shale formation. See Appendix B for General Stratigraphic Column for the Grand Junction area and Appendix C a West to East Cross Section of the Piceance Basin. It is the combination of those two natural-gas-bearing reservoirs -- one old, one new -- that should be of particular interest to any party looking for an investment in long-term natural gas reserves. WILLIAMS FORK FORMATION The Williams Fork formation made the Piceance Basin what it is today. The Piceance Basin covers all or part of seven counties in western Colorado, just to the north and east of Grand Junction. See Exhibit D Piceance Basin Map. Exhibit D Piceance Basin Map The largest production growth in the Piceance Basin occurred in 2000 through 2008 as can be seen in Exhibit E. The year-over-year production growth during that period averaged 20 percent or more.! 6

8 Exhibit E Annual Natural Gas Production in Counties That Contain the Piceance Basin County Delta Garfield Gunnison Mesa Moffat Pitkin Rio Blanco TOTAL (Bcf) TOTAL (MMcf/d) Y/Y % Change N/A 12.5% 26.3% 17.9% 27.4% 25.3% County Delta Garfield Gunnison Mesa Moffat Pitkin Rio Blanco TOTAL (Bcf) TOTAL (MMcf/d) Y/Y % Change 23.9% 26.4% 9.0% 8.6% 4.5% 1.5% Note: These figures are largely driven by Piceance production, but may contain some production from other formations. Source: Colorado Oil & Gas Conservation Commission data, NGI s Shale Daily calculations % TOTAL N/A N/A That production growth was significantly curtailed when natural gas prices decreased beginning in the first quarter of The decline in the drilling rig count correlates directly with the decline in natural gas prices as can be seen in Exhibit F.! 7

9 Exhibit F - Decline of Natural Gas Price Index Since 2008 and Piceance Basin Rig Count 2008-Current (By Quarter) $ $8.00 $ per MMBtu $6.00 $5.00 $4.00 $ # of Rigs $2.00 $ $ Q1'08 Q3'08 Q1'09 Q3'09 Q1'10 Q3'10 Q1'11 Q3'11 Q1'12 Q3'12 Q1'13 Q3'13 Q1'14 Q3'14 Northwest Rocky Mountain Index Piceance Basin Rig Count Source: Inside FERC s Gas Marketing Report, A McGraw Hill Publication and Tudor Pickering Holt & CO data Despite lower natural gas prices, some producers such as WPX are still very active in the basin. Clearly their size and economy of scale create a competitive advantage. WPX invested $500 million into their world class asset in the Piceance Basin in 2014 and $7 billion (counting their predecessor companies) in the last decade. The Tulsa, Okla.-based company operates a total of 4,300 wells in the Piceance. WPX s Piceance Basin assets account for 60 percent of their total production and 70 percent of total reserves. WPX s dry gas production currently exceeds 600,000 MCF/day. WPX is the pioneer of the pad drilling concept in the Piceance. Pad drilling employs self-moving, fit-forpurpose Tier One rigs that employ simultaneous drilling completion and production practices. WPX can drill as many as 22 wells from one pad site in an environmentally friendly way. For WPX, the process has become a gas manufacturing one with little risk of failure. DEEP MANCOS SHALE A number of operators in the Piceance Basin are also utilizing horizontal drilling and hydraulic fracturing to explore the deep Mancos shale rock (a.k.a. Niobrara shale) in the Piceance Basin.! 8

10 WPX Energy drilled a Mancos well (the Beast well) that produced one BCF of natural gas in its first hundred days of production. That volume compares with the output that a typical Williams Fork well would take 40 years to produce. WPX s Beast well was drilled to 10,200 feet with a 4,300-foot horizontal lateral. The initial production (IP) flow rate was 16,000 MCF/day. (An average Williams Fork well would produce 450 MCF/day.) A second Mancos test well drilled to the east in the Rulison field confirmed the Mancos as a resource play. WPX has more than 180,000 acres of prospective deep Mancos acreage in western Colorado. Encana Corp. operates approximately 3,000 wells in the Piceance Basin. Encana has also explored the Mancos resource play with great success. A list of Piceance Basin producers who have drilled horizontal Mancos wells is included as Appendix D. A Partial List of Current Piceance Basin Operators can be found as Appendix E and a list of the Mancos wells can be found as Appendix F. LONG TERM TRANSACTIONS IN THE PICEANCE BASIN In the fall of 2012, analysts were surprised by an announcement by Charlotte, N.C.-based Nucor Corp. (the largest steel manufacturer in the U.S.) and Encana Corp. According to Encana s website, Nucor is to earn a 50 percent working interest in certain natural gas wells to be drilled over the next 20 years in the Piceance Basin in Colorado. Nucor has agreed to pay its share of well costs plus a portion attributable to Encana s interest. The joint venture calls for a 50/50 drilling program in the Williams Fork on 50,000 acres of Encana s Big Jimmy Federal Unit in Garfield and Rio Blanco counties in Colorado. Nucor s total investment could approach $3.6 billion over 22 years. Monetarily, this transaction easily ranks among the top five long-term natural gas transactions completed in the U.S. in the last 10 years. Nucor s strategy is fairly simple. They will produce natural gas in Colorado, sell the gas in western U.S. markets and use the proceeds to purchase natural gas supply for their billion dollar steel plant located in Louisiana. Nucor recognizes that the physical molecule of natural gas produced in western Colorado will not be transported and consumed in Louisiana but it provides what they describe as a dirty hedge. In essence, they are protected from potential huge price spikes in natural gas over the 20 years of the contract. That same dirty hedge strategy could be employed by a potential foreign LNG purchaser that is counting on stable, predictable U.S. natural gas pricing over the next 20 years. In the summer of 2014, WPX Energy and Houston-based G2X, a methanol manufacturer, entered into a similar long-term, joint venture development project wherein G2X paid $40 million in cash for an interest in 100 existing producing wells in the Trail Ridge area of the Piceance Basin. Those wells currently produce approximately 7,700 MCF and 200 barrels of natural gas liquids per day. WPX will continue to act as operator. G2X made an additional commitment of $170 million to pay for future drilling. The drilling program calls for eight wells to be drilled in 2014, 25 wells in 2015, 50 wells in 2016 and 100 wells per year in 2017 and beyond. G2X will earn a 49 percent working interest in the producing wells according to WPX.! 9

11 WPX has more than 3 trillion cubic feet of proved reserves (in the Piceance Basin), according to WPX spokesperson Kelly Swan. We have an enormous profile there, and this deal will allow us to more fully develop one of the fields that s been waiting in the wings. Swan continued, As a company, you only have so much capital, and this brings more capital to the table to more fully develop the property. The potential is there, the locations are there, the question was when could we get to it and now we can. Alan Harrison of WPX Energy described the ways in which the Piceance Basin components converge to make investment so appealing: The net effect of a joint venture transaction is that the operator is paying less capital, i.e., the net cost to drill a well is less, thus raising your rate of return. It lessens the price threshold the operator requires to drill a well, he said in a recent interview. Those two examples of long-term, Piceance Basin investments by U.S.-based industrial users of gas -- one a steel manufacturer and the other a manufacturer of methanol -- are indicative of the Piceance Basin s potential importance to the long-term strategy of an LNG investor. The Piceance Basin has the combined benefit of significant existing production, plus tens of thousands of additional locations yet to be drilled in the Williams Fork, all on top of an emerging Mancos Shale natural gas play. There are some estimates that the Mancos Shale play could hold reserves in excess of 100 TCF or approximately 5 percent of the PGC s current estimate of total reserves in the U.S. The reserve base of the Piceance is important but the marketability of those reserves is also critical. That marketability depends solely on the capacity to move the gas to markets. Guy Dayvault, Commercial Director for Jordan Cove Energy s LNG project in Coos Bay, Ore., put it best in a recent interview: Simply owning the resource in the ground doesn t solve the problem. You still have to develop, produce, nominate and schedule the gas; you still have to have pipeline transportation capacity; and you have to manage that capacity. Therein lies the additional hidden value of the Piceance Basin. Significant capacity in existing midstream natural gas processing and pipeline capacity infrastructure is already in place and available. MIDSTREAM INFRASTRUCTURE In 2008 and 2009, Piceance Basin producers responded to record-high natural gas prices with rig counts that approached 100 active rigs in the basin. That drilling response required a significant midstream build-out. In an effort to avoid regional shut-in gas concerns experienced by some Rocky Mountain natural gas producers in the 1980s and 1990s, western Colorado producers aggressively addressed mid-stream issues to effectuate the ultimate sale of their product.! 10

12 Between , the net export capacity of interstate natural gas pipelines out of western Colorado nearly tripled, from million MMBtu/day to million MMBtu/day. Natural gas processing facilities experienced a similar growth pattern. For example, Enterprise Product Partners constructed a 1.5 million MMBtu/day natural gas processing plant near Meeker, Colo. (Greasewood/Meeker/White River Hub Area). In addition to the Enterprise effort, the Williams Companies constructed the Willow Creek Processing Plant that is capable of processing 450,000 MMBtu/day of Piceance Basin natural gas production. Since 2009, the decline in the natural gas price saw a commensurate decline in the rig count (as shown previously in Exhibit F). As a result, the production volumes forecasted six years ago have not materialized. Most, if not all, midstream gathering and processing and interstate pipelines in western Colorado have significantly underutilized capacity. NATURAL GAS PIPELINE TRANSPORTATION OUT OF WESTERN COLORADO There is approximately 300, ,000 MMBtu/day of available transportation capacity on REX pipeline from the White River Hub (near Meeker, Colo.) area to Wamsutter, Wyo. That segment of REX Pipeline has a maximum capacity of 1.3 million MMBtu/day. Exhibit G shows the average daily net volume transported through that segment of REX pipeline for the last two years as measured against total available pipeline capacity. Delivering gas to the Wamsutter area allows access to Ruby Pipeline, Kern Pipeline and Northwest Pipeline (for redelivery to western U.S. markets) and to Colorado Interstate Gas (CIG), REX Pipeline and Wyoming Intrastate Company (WIC) (for redelivery to mid-continent and eastern U.S. markets). 11!

13 Exhibit G REX Capacity: White River Hub to Wamsutter Bcf/d Source: Bentek Energy REX White River to Wamsutter REX White River to Wamsutter Ave Capacity The Williams Company s Willow Creek Processing Plant is tied into a significant, 142-mile, 24-inch diameter natural gas pipeline, owned and operated by the Wyoming Interstate Co., Ltd. (WIC) (a KinderMorgan Company). That WIC Piceance Lateral expansion transports gas northward from the Greasewood Hub (near Meeker) in Colorado s Rio Blanco County to the Wamsutter Compression Station in southwest Wyoming. The WIC Piceance Basin lateral expansion is capable of transporting 350,000 MMBtu/day out of the Piceance Basin. The Williams Companies determined at an early stage of development that they would build their own pipeline system northward to Wyoming, refusing to join with Encana on a long-term commitment to Rockies Express Pipeline (REX). See Exhibit H.! 12

14 Exhibit H Wyoming Interstate Company (WIC) System Source: El Paso Pipeline Partners, L.P. Form S-1 The collective efforts by producers, gathering companies, processing companies, and interstate pipelines have resulted in world-class facilities that resolved any regional pipeline takeaway capacity issues in western Colorado. The collective efforts were so significant, some industry observers would argue that midstream processing and interstate pipeline capacity in western Colorado is currently over-built. A table that displays the historic and existing pipeline export takeaway capacity out of the Piceance Basin is shown as Exhibit I.! 13

15 Exhibit I Growth in Piceance Basin Pipeline Takeaway Capacity* December 2005 February 2006 Summer 2006 Summer 2007 Summer 2008 Summer 2013 CIG (Net) 90,000 90,000 90,000 90,000 90, ,000 Northwest Pipeline North 330, , , , , ,000 Northwest Pipeline South 440, , , , , ,000 Questar Pipeline (Net) 25,000 25,000 25,000 25,000 25,000 35,000 TransColorado 350, , , , , ,000 WIC 30,000 30, , , , ,000 REX / Entrega (Segment 1) 500, , ,000 1,300,000 1,300,000 Total Pipeline Export Capacity 1,265,000 1,800,000 2,120,000 2,370,000 3,370,000 3,922,000 * All numbers in MMBtu/ day NATURAL GAS PIPELINE TRANSPORTATION OUT OF THE ROCKIES The Western U.S./Central Rockies Production area (Colorado, Wyoming and Utah) has been a net exporter of natural gas since the 1960s. The interstate pipeline corridors that allow Piceance basin gas to exit Western Colorado are shown in Exhibit J. Exhibit J Rockies Pipeline Infrastructure Source: Bentek Rockies Observer! 14

16 Historically, Central Rockies production values and reserves were discounted due to a lack of regional demand. That discount or basis differential has been extreme at times. Basis differential is defined as the price differential between the NYMEX Natural Gas Futures Contract and, in this analysis, the Northwest Pipeline - Rockies First of the Month Index, (as reported by Inside FERC Gas Market Report, a McGraw Hill Publication). (Inside FERC index prices are determined by arms-length price negotiations reported to McGraw Hill from a variety of buyers and sellers of gas at a specific delivery point - e.g., western Colorado for a specific time period.) Since January 2010 the annual basis differential between Northwest Rockies and NYMEX has averaged a negative $0.23 per MMBtu. (See Exhibit K) Exhibit K - Basis Differential Between Northwest-Rockies and NYMEX 2010-Current per MMBtu $0.80 $0.60 $0.40 $0.20 $0.00 -$0.20 -$0.40 -$0.60 -$0.80 -$1.00 -$1.20 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11 Jul-11 Oct-11 Jan-12 Apr-12 Jul-12 Oct-12 Jan-13 NW Rockies vs. NYMEX Source: Inside FERC s Gas Market Report, A McGraw Hill Publication Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 During the last four years, significant natural gas pipeline export capacity has been constructed and put into service exiting the central Rockies. Those export pipeline expansions have had a significant positive effect on the negative Rockies basis differential narrowing it dramatically. Exhibit L shows the collective total of all natural gas pipeline capacity (listed as 100 percent LF Load Factor) exiting the Rockies. The green shaded area of the exhibit depicts the total available production in the Rockies. Whenever total available production exceeded the total pipeline takeaway or export capacity, producers were at the mercy of the parties who held pipeline transportation capacity contracts. A close examination of the exhibit will show that pipeline capacity has exceeded production capacity since approximately That excess capacity explains the price differential between Rockies natural gas and the NYMEX natural gas contract, and how it has been reduced so dramatically. In effect,! 15

17 there is no significant price difference between Rockies gas and gas prices in Texas and Louisiana, as shown above on Exhibit K. Exhibit L Rockies Supply vs. Regional Export Capacity Source: George Wayne, Colorado Interstate Gas In another analysis of available pipeline takeaway or export capacity, Brian Jeffries, Executive Director of the Wyoming Pipeline Authority has analyzed the total available pipeline capacity exiting the Rockies (10.2 BCF/day) and then compared it to the actual total flows of natural gas moving through those pipelines exiting the Rockies on a given day (Oct. 13, 2014). See Exhibit M. An October analysis of that capacity is much more representative of the average annual flows than an analysis on a winter or summer day because the temperatures are less extreme. Only 58 percent of the westward total available pipeline capacity was being utilized. Only 42 percent of the eastward total available pipeline capacity was being utilized. No other production area in the country has anywhere near that total excess available pipeline capacity.! 16

18 Exhibit M - Rockies Pipeline Infrastructure Gas flow out of central Rockies Oct 13, Bcf per day capacity Northern Border PL Northwest PL 14 PRB Bison 241 Ruby 1116 Opal TIGT 110 Trailblazer 576 Salt Lake Unita/Piceance Cheyenne Hub Rockies Exp 1147 Southern Star 113 TransColorado 164 Cheyenne Plains 203 Kern 2229 Northwest PL 191 Denver Westbound Total = 3714 (58 % of total flow) CIG 317 Eastbound Total = 2707 (42 % of total flow) 1 Source: Brian Jeffries, Wyoming Pipeline Authority (WPA) Two of the more significant pipelines in Brian Jeffries analysis are naturally two of the larger capacity pipelines, specifically Rockies Express Pipeline (REX) and the Ruby Pipeline. They each deserve a deeper analysis in the context of what their available capacity means to U.S. LNG exports and how those potential exports could be linked to the Piceance Basin. ROCKIES EXPRESS PIPELINE (EASTBOUND) The largest volume interstate pipeline with takeaway capacity directly out of the Piceance basin is clearly Rockies Express (REX) Pipeline at 1.3 million MMBtu/day. (REX Pipeline capacity downstream of the Cheyenne Hub telescopes up to 1.8 BCF/day.) KinderMorgan Energy Partners, Sempra Pipelines and Storage, and ConocoPhillips joined forces to build one of the largest natural gas pipelines ever constructed in the United States. Rockies Express is a 1,679-mile, 1.8 BCF/day (1.3 BCF/day in the Piceance Basin) pipeline that stretches from the Meeker Hub in Rio Blanco County, Colo., eastward ultimately to the Clarington Hub in Monroe County, Ohio.! 17

19 The $4.4 billion project received binding capacity commitments from all its shippers and began full service in June Encana Corporation filed the first permit applications for the Entrega Gas Pipeline in The initial segment of pipe from Meeker, Colo., to Cheyenne, Wyo., went into service on Feb. 14, The initial volume of gas free flowing (no compression) on those 328 miles of Rockies Express was approximately 400,000 MMBtu/day. The 36-inch diameter pipe from Meeker to Wamsutter, Wyo. is capable of transporting up to 1.3 million MMBtu/day. Entrega then morphed to become Rockies Express Pipeline, LLC, with plans to build two larger segments, Zone 2 and Zone 3. Zone 2 would stretch from Cheyenne to eastern Iowa; and Zone 3 would stretch from Iowa to Clarington. Exhibit N Rockies Express Pipeline Once Piceance Basin gas is delivered into the main west-to-east segment of REX, the available transportation capacity grows significantly. This can be seen in Exhibit O that shows the historic capacity that is available from Wamsutter, Wyo. to the Cheyenne Hub.! 18

20 Exhibit O REX Capacity: Wamsutter to Cheyenne Hub Bcf/d REX Wamsutter to Chey Hub Source: Bentek Energy REX Wamsutter to Chey Hub Ave Capacity Rockies Express (REX) is currently owned through a joint venture of Tallgrass Development, L.P. (a private limited partnership), Sempra Energy and Phillips 66. The Entrega shippers that committed to move gas from Meeker to Wamsutter are listed in Exhibit P.! 19

21 Exhibit P REX (Entrega) Anchor Shippers Shipper Capacity (MMBtu) Contract Expiration Berry Petroleum Company 10,000 11/11/2019 Bill Barrett Corporation 25,000 11/11/2019 BP Energy Company 200,000 11/11/2019 ConocoPhillips Company 250,000 11/11/2019 Encana Marketing (USA) Inc. 500,000 2/13/2022 Marathon Oil Company 12,000 11/11/2019 Occidental Energy Marketing, Inc. 120,000 12/8/2019 Sempra Rockies Marketing LLC 100,000 11/11/2019 WPX Energy Marketing, LLC 165,000 12/31/2015 Wyoming Interstate Company, L.L.C. 80,000 12/8/2019 1,462,000 RUBY PIPELINE (WESTBOUND) During the last two years, Ruby Pipeline has only seen an average 61 percent capacity utilization rate. Stated another way, nearly 40 percent of the capacity on Ruby Pipeline is unused and available. See Exhibit Q.! 20

22 Exhibit Q Ruby Capacity Ruby Bcf/d Opal to Malin Ave Capacity Source: Bentek Energy In September 2014, Veresen Inc., a Calgary-based Canadian company agreed to purchase Global Infrastructure Partners 50 percent interest in Ruby Pipeline for $1.5 billion. Ruby Pipeline will continue to be operated by KinderMorgan. Veresen is partial owner of the $5.3 billion Jordan Cove LNG project in Coos Bay, Ore.! 21

23 Exhibit R Ruby Pipeline Map According to Veresen s President and Chief Executive Don Althoff, While there is no question in our minds that Ruby as a standalone investment is an excellent addition to our portfolio of assets, Ruby s inherent synergy to our proposed Jordan Cove LNG project creates tremendous upside potential. Veresen is also a 50 percent owner of the proposed $1.5 billion 230-mile Pacific Connector pipeline that would link Ruby Pipeline with the Jordan Cove LNG project. (Northwest Pipeline, a Williams Company will own and operate the remaining 50 percent.) See Exhibit S.! 22

24 Exhibit S Pacific Connector Pipeline Source: Oregon Green Energy Guide Clearly, the acquisition by Veresen of a 50 percent stake in Ruby Pipeline is an extremely positive sign for the Jordan Cove LNG project. The Jordan Cove LNG project is the closest project to the Piceance Basin in terms of geographic proximity. However, it is not the only LNG export project that could be linked to Piceance Basin production. Ruby Pipeline and REX pipeline act as huge conduits for the export of Rocky Mountain natural gas production. Thanks to those pipelines and their available capacity, any party committing to capacity in any LNG export project in the U.S. or Canada could pursue reserves in the Piceance Basin in the same fashion as Nucor Steel and G2X. A commitment to reserves in the Piceance Basin by any foreign purchaser of U.S. LNG would extinguish any exposure to price volatility over a 20-year time frame. In essence, a foreign purchaser of U.S. LNG could accomplish the same dirty hedge as Nucor Steel and G2X. LNG EXPORTS According to the International Energy Agency (IEA), worldwide trade in LNG will increase by 40 percent up to 450 billion cubic meters (16 trillion cubic feet TCF) by It is expected that U.S. LNG exports will amount to 8.5 BCF per day by 2020 according to an IHS energy analysis, equal to approximately 1.8 percent of global demand.! 23

25 A quick review of recent world LNG prices explains in one picture the level of interest in exporting U.S. natural gas to other parts of the world. See Exhibit T. Exhibit T World LNG Prices ($U.S./MMBtu) Source: Waterborne Energy, Inc. The total of all U.S.-proposed export projects exceeds 30 BCF/day in total liquefaction capacity, roughly equaling 50 percent of current world liquefaction capacity. The desire to export can easily be seen in Exhibit T where U.S. prices are compared to international prices for landed LNG. The price arbitrage is a great motivation, but it is difficult to imagine that the requisite construction and development financing is (or would be) available for all the proposed projects. There are essentially two types of permits for LNG exports granted by the Department of Energy (DOE). During the last three years, it has been far easier to receive a permit to export LNG to a Free Trade Agreement country than to a non-free Trade country. The total demand among all our Free Trade Agreement partners would not be enough to prompt construction of one export facility. The key to LNG exports then for any promoter of such a project is to receive approval to export natural gas to a non-fta country. Those non-fta approved U.S. LNG export projects are summarized in Exhibit U.! 24

26 Exhibit U Current DOE LNG Export Approvals Company Maximum Non-FTA Quantity (BCF/D) Sabine Pass Liquefaction, LLC 2.2 Freeport LNG Expansion, LP and FLNG Liquefaction, LLC 1.4 Lake Charles Exports, LLC 2.0 Dominion Cove Point LNG, LP 0.77 Freeport LNG Expansion, LP and FLNG Liquefaction, LLC* 0.4 Cameron LNG, LLC 1.7 Jordan Cove Energy Project, LLC 0.80 *The second application from Freeport LNG Expansion (FLEX) was for authorization to export 1.4 BCF/D to FTA and Non-FTA countries. DOE granted the application but only authorized an additional 0.4 BCF/D to Non-FTA countries, so as to match the total authorized volume to Non-FTA countries in the two FLEX Non-FTA orders with the FLEX application to FERC for a total facility capacity of 1.8 BCF/D. Source: NERA Economic Consulting Total 9.27 A summary of existing, proposed and potential LNG facilities can be found as Appendix G. The U.S. is not the only country seeking to export natural gas. There is a global race underway to build the necessary pipeline and liquefaction infrastructure to export LNG. More than 50 international LNG plants are either under construction or facing their own final investment decision within the next 18 months. There are 12 LNG export facilities proposed in western Canada (and two additional in Oregon). See Exhibit V.! 25

27 Exhibit V Export License Volumes for Canadian LNG Projects Project Total (Tcf) Annual (Tcf) Daily (Bcf) Aurora LNG BC LNG Goldboro LNG Jordan Cove LNG Kitsault LNG KM LNG LNG Canada Oregon LNG Pacific NorthWest LNG Prince Rupert LNG Stewart LNG Triton LNG WCC LNG Woodfibre LNG TOTALS Canadian gas export license granted 2 Nova Scotia terminal site 3 Oregon terminal site Source: National Energy Board The 50 plants represent an extremely significant worldwide investment, considering that the average cost of one LNG export facility can range from $4 billion to $12 billion, depending upon its ultimate size. Parties who are opposed to U.S. LNG exports claim that any export volume will raise the price of natural gas for U.S. consumers. This theory is difficult to comprehend, given the comparative size of projected U.S. exports vs. the U.S. natural gas resource base. See Exhibit W. Exhibit W! 26

28 For the third time in the last 18 months, the DOE has changed the rules for the licensing of U.S. LNG export facilities to non-free Trade Agreement (non-fta) countries. The rule-changes by the DOE essentially eliminate the former practice of issuing conditional orders. The rule-changes also erase the queue established in December 2012 by which the DOE previously handled applications. The DOE is also requiring a sequence for issuance of final decisions based on an environmental review process that is required under the National Environmental Policy Act (NEPA). The timing of the DOE s rule-changes is profoundly dysfunctional considering events in Ukraine and Russia s near monopoly position in supplying natural gas to most of Europe. That negative development is not lost on several U.S. Senators who noted that our allies await a strong market signal regarding the United States willingness to supply LNG, even if those supplies are not immediately available. The strategic implications would be profound, positive and immediate. Additionally, the American Petroleum Institute (API) accused the DOE of arbitrarily eliminating an important signaling mechanism to markets (both for U.S. project financing and for natural gas commodities globally) and to our strategic allies. During the last 18 months, the DOE has granted LNG exports at a glacial pace. The American Petroleum Institute (API) concurs and said as much in comments to the DOE: DOE has managed to review non-fta applications at an anemic rate of about one per quarter since the Order of Precedence (issued Dec. 5, 2012) was established, and has reviewed only about one-fifth of the total applications submitted. At this rate, and assuming no additional applications were submitted, DOE would have completed its reviews sometime after 2020 an unjustifiable and absurd result. Receiving regulatory approval to build does not mean that the LNG developers work is done. Typically, project owners must receive a commitment to percent of their throughput capacity before a project can be financed. With each passing day, foreign LNG supplies win the competition for worldwide demand, while potential U.S. LNG supply faces seemingly endless regulatory hurdles. Global demand for natural gas is expected to increase between 18 Bcf/day and 38 Bcf/day by ICF International expects worldwide liquefaction capacity outside the U.S. to expand by nearly 50 Bcf/ day by Current U.S. export projects at the DOE account for deliveries of approximately 35 Bcf/ day of LNG. According to ICF, With projections of world demand for LNG ranging from Bcf/day by 2025, global LNG supply may exceed demand. Since the meltdown of the Fukushima Dai-Ichi nuclear plant, Japan s LNG imports have jumped to record highs. The cost of each MMBtu in a U.S. LNG tanker delivered to Japan would be approximately $10.50 per MMBtu. According to government data, Japan paid more than $15.50 per MMBtu for shipments from Australia. Clearly, Asia would like to be less vulnerable to imports from Qatar and Australia, and would welcome U.S. LNG with open arms.! 27

29 The historical worldwide model for the construction of LNG import and export facilities required a specific producing field to be dedicated to the export facility. U.S. LNG developers have not adopted that model. Some analysts have described U.S. LNG export facilities as speculative in nature. That is to say, specific reserves have not been dedicated to the export facility. However, foreign purchasers of natural gas are expected to eliminate the one uncertainty in the vertical integration of natural gas supply-and-demand via LNG exports by committing to investments in U.S. reserves. Additionally, most historic LNG supply contracts have been linked to crude oil prices. In perhaps the biggest positive contribution to world natural gas prices, the U.S. Shale Revolution has changed that pricing phenomenon, as reflected in recent contract negotiations for long-term LNG contracts in the Asian market. CONCLUSION There is a limited window of opportunity for the regulatory approval and marketing of U.S. LNG export projects. The global race to build LNG export facilities to meet the finite need for worldwide demand allows U.S. politicians and regulators no time to waste. (See Appendix H for complete list of World LNG Liquefaction Capacity, Existing, Under Construction and Proposed.) Additionally, a potential global economic slowdown could accelerate the closure of that window of opportunity for long-term export of U.S. natural gas production. Politicians at the county, state and federal levels must realize that their support or opposition to U.S. LNG exports weighs heavily on investors and potential customers final investment decisions. Countless studies, even the Department of Energy s own study, point to the huge economic benefit of U.S. LNG exports to the U.S. economy. But it s not just about benefiting the U.S. economy. The U.S. has the geopolitical opportunity to help contribute to a predictable market for worldwide trade in LNG. Unpredictable suppliers create unpredictable markets. Russia s historical on-again, offagain natural gas supplies to Europe underscore that point. The predictability of Piceance Basin reserves and abundant midstream processing and pipeline export capacity should be very attractive to any foreign country or foreign consumer of LNG. It would be unusual for those entities to invest in regasification facilities in their own countries, into LNG shipping, into capacity in U.S. LNG plants, and not into the commodity of natural gas at the production level. Without complete vertical integration, from reserves and production to the final point of consumption, that foreign consumer of U.S. LNG is at risk for commodity price volatility. A foreign LNG purchaser s potential investment in reserves and the impact on western Colorado is possibly foreshadowed by Nucor Steel s (through Encana as operator) activity in the Piceance Basin in In 2013, nearly 50 percent of the total drilling rig count in the Piceance Basin was attributable to the 20-year-plus transaction between Encana and Nucor Steel. Nucor s total investment in western Colorado drilling could ultimately exceed $3 billion over 20 years.! 28

30 The current 3-year forecasted price for natural gas for western Colorado production may not meet every natural gas producers threshold price for the accelerated development of their Mancos Shale reserves. However, additional foreign markets interested in U.S. LNG exports operate beyond a threeyear price forecast. Their potential investment in Piceance Basin reserves (both Williams Fork and Mancos Shale) could increase the Piceance Basin rig count significantly. Exposure to those potential markets and potential investment will only occur through increased exports of U.S. LNG. By inviting partners into their development plans, Piceance Basin producers can change that threshold price required for an acceptable rate of return on their own share of investment dollars in the Piceance Basin. U.S. LNG exports could accelerate the expansion of drilling and production in Western Colorado. The Piceance Basin s unique attributes of predictable reserves and available, existing midstream pipeline capacity should be marketed to all potential foreign buyers of U.S. LNG.! 29

31 APPENDIX A Scale Chart 1 MCF = 1,000 cubic feet = the volume of gas required to fill a room 10 ft x 10 ft x 10 ft 1 MCF = 1 MMBtu (1 million British thermal units) (approximately) 84 MCF = the volume of gas the average U.S. home uses per year 16,000 MCF/day = initial production from WPX s Beast well 450,000 MMBtu per day = Williams Willow Creek Processing Plant capacity 600,000 MMBtu/day = WPX s current daily production in the Piceance Basin 800,000 MMBtu/day = approximate daily volume for Jordan Cove s (Coos Bay, OR) LNG takeaway capacity (based on a 6 mtpa [million tons of LNG per annum] sized facility) 1 BCF (billion cubic feet) = production from WPX Beast well during the first 100 days 1 BCF = equals the amount of energy found in a swath of wooded natural forest 800 feet wide by 120 miles long 1.3 BCF per day = total capacity of Rockies Express Pipeline (REX) White Rive Hub, Meeker, CO to Wamsutter, WY 1.5 BCF per day = Enterprise Product Partners Meeker, CO processing plant capacity. 1.5 BCF = average lifetime production from Piceance Basin Williams Fork well 1.5 BCF per day = total capacity of Ruby Pipeline 2.0 BCF per day = total capacity of Rockies Express Pipeline (REX) Wamsutter, WY to Cheyenne Hub, WY 2.1 BCF per day = approximate peak day demand for natural gas in Front Range Colorado (PSCO service territory) 2.6 BCF = approximate peak day demand in New York City 2.8 BCF/day = Cheniere Energy Sabine Pass approximate daily takeaway capacity 3 BCF = average size of liquefied natural gas (LNG) tanker (enough to heat 35,000 homes for one year) 8 BCF = the average daily amount of natural gas consumed in California 9.02 BCF = approximate daily 2013 U.S. commercial sector consumption! 30

32 9.2 BCF per day = anticipate U.S. LNG daily export, final investment decision in BCF per day = approved non-fta LNG export licenses 10.2 BCF per day = total Rockies pipeline export capacity BCF = approximate daily 2013 U.S. residential consumption BCF = approximate daily 2013 U.S. industrial consumption BCF = approximate daily 2013 U.S. electric power sector consumption 65 BCF/day = current average daily U.S. natural gas production 80 BCF = the average annual consumption of Nucor Steel (largest steel producer in U.S.) 8.3 TCF (trillion cubic feet) = total natural gas production in Texas in TCF = European Union s 28 member countries natural gas consumption in TCF = total consumption of natural gas in U.S. in TCF = Noble Energy natural gas reserves offshore Israel 70 TCF = Anadarko natural gas reserves offshore Mozambique 347 TCF = 2008 U.S. shale gas resource 1,073 TCF = 2013 U.S. shale gas resource 2,384 TCF = 2013 Potential Gas Committee s estimate of U.S. technically recoverable natural gas reserves Conversions 1 cubic meter = cubic feet 1,000 cubic feet = 1 MCF = 1 MMBtu 1,000,000 MCF = 1 BCF 1,000 BCF = 1 TCF (one trillion cubic feet) 1-3 BCF LNG Tanker = 3,000,000 MCF = 3,000,000,000 cubic feet = 84,950,539 cubic meters 3 BCF = 84,950,539 cubic meters X 365 (days) = 31,006,946,735 cubic meters per year Total 2013 U.S. consumption = 28 BCF! 31

33 APPENDIX B General Stratigraphic Column for the Grand Junction area Source: Oil and Gas Potential and Reasonable Foreseeable Development (RFD) Scenarios in the Grand Mesa, Uncompahgre, and Gunnison (GMG) National Forests Colorado! 32

34 APPENDIX C Cross Section from West to East of the Piceance Basin Source: Summit County Citizens Voice, Posted on May 3, 2011 by Bob Berwyn! 33

35 APPENDIX D Piceance Basin Producers Who Have Drilled Mancos Wells Encana Oil & Gas (USA) Incorporated Black Hills Plateau Production LLC Maralex Resources Incorporated WPX Energy Rocky Mountain LLC Chevron USA Incorporated Oxy USA WTP LP Piceance Energy LLC Gunnison Energy Corp.! 34

36 APPENDIX E Partial List of Current Piceance Basin Operators Encana Corporation WPX Energy Caerus Oil and Gas Gunnison Energy LLC Foundation Energy Management, LLC Vaquero Energy, Inc. Piceance Energy LLC Chevron Corporation Marathon Oil Corporation Occidental Petroleum Corporation Noble Energy Inc. Laramie Energy, LLC Mesa Energy Partners, LLC Southwestern Energy Ventures Company LLC BOPCO, L.P. XTO Energy Inc. Wexpro Whiting Petroleum Corporation LINN Energy, LLC! 35

37 APPENDIX F - Mancos Wells Source: Roan Creek Resource Report, Garfield County, Colorado, USA Dejour Energy (USA) Corp., June 1, 2014! 36

38 APPENDIX G! 37

39 APPENDIX G! 38

40 APPENDIX G! 39