Lessons from the Natural Gas Market

Capital Trends and Risks Associated with Natural Gas-related Investment The unprecedented opportunities for natural gas markets, resulting principally from the continuing evolution of hydraulic fracturing technologies in North American shale fields, has created both substantial investment opportunities and capital needs over the past few years. Readily available capital raised prior to the 2008 recession helped to fund successful investments by many companies well-positioned to pursue and exploit shale gas exploration opportunities. This capital availability, however, became a catalyst for failure of certain companies that did not appropriately evaluate the risks resulting from issuing debt during a period of significant market shifts.

The oil and gas sector has historically attracted significant investment capital, which typically ebbs and flows through boom and bust market cycles. The current environ-ment of aggressive borrowing to fund sector growth and investment will inevitably lead to future financial distress in the sector, just as it has in the past. Understanding trends, lessons learned during sharp price declines, and how certain non-traditional parties have successfully profited during such times of adversity, provides insight on how to effectively navigate future cycles and the uncertainty they bring.

Significant Sector Changes Over Time

For the years that led up to the 2008 recession, natural gas prices got to an unprec-edented point where they were stubbornly high. The discovery and development of low-cost, low-risk shale gas picked up speed as the commercialization of horizontal drilling kicked off a shale gas “land rush” by the industry. Market participants were active in securing strong leasehold positions and services businesses were bulking up in support of anticipated growth in the unconventional sub-sector. Merger and acquisition (M&A) activity in the natural gas sector was robust, driven largely by confidence in conventional drilling activity and an expectation of sustained high pric-ing levels supporting healthy margins (with capital also being directed to unconven-tional drilling activity during this period). Transaction and investment activity was strongly supported by a debt financing market that provided the necessary capital to support funding of both M&A activity in the sector and related investment needs.

As the financial meltdown ensued, exacerbated by an anticipated glut in natural gas led by large discoveries of unconventional shale gas and the collapse in natural gas demand, the natural gas industry experienced a significant and swift decline in prices and rig counts. Capital markets froze, adding stress to an already troubled sector, resulting in a slowdown in transactional activity. Energy sector bankruptcies rose, re-flecting a dearth of critical capital availability to support companies ineffectively po-sitioned to sustain the falling commodity price environment and challenging capital markets that followed. The hydraulic fracturing story, as an area of growth, contin-

A publication by Navigant’s Energy Practice » January 2013

Contents1 Lessons from the

Natural Gas Market – Capital Trends and Risks Associated with Natural Gas-related Investment

7 Natural Gas Market Charts

10 Legislative and Regulatory Highlights

13 About Navigant

2

January 2013

ued to build momentum during this time with select companies restruc-turing and repositioning for a greater share of this growing opportunity. Many natural gas producers began to redirect to liquid-rich plays (oil and wet gas), acquiring lead positions where they had the capital availabil-ity or ability to issue debt.

While hydraulic fracturing has been validated through substantial in-creases in production capacity, a “new normal” has emerged in terms of a low priced but stable natural gas pricing environment likely to prevail for a meaningful period of time. Un-conventional drilling activity has not only created an abundance of supply, but also a significant shift in inter-est to ”wet” or liquids rich natural gas development and a shift to oil directed drilling exploration. Rigs are migrating to oil, and while oil prices have declined recently they have held their comparative heat value price advantage to natural gas. Hydraulic fracturing has incented drilling for oil, and as a result, both significant capital investment and rigs previous-ly used for natural gas are now being earmarked for oil. And, this activity is changing market dynamics.

The United States now has the po-tential to become more self-sufficient for its oil needs. LNG import termi-nals are being retooled for anticipated significant future export activity, and access to capital markets has returned in a meaningful way due to improving lender and investor confidence. The confluence of these factors is creating attractive opportunities for companies.

Merger & Acquisition Activity Reflecting Strategic Views of Buyers and Sellers

The current market dislocation, driv-en by abundant natural gas supply, has created a recovery in M&A activ-ity in the oil and gas sectors starting in 2010, including unconventional oil and gas. Activity in the services and midstream sectors, as represented in Figure 1, while down in 2012 relative to a significant year of transactional activity in 2011, has principally been directed by:

» A rapid shift from natural gas drilling and production to oil and liquids-rich directed plays.

» An increase in the impact of development drilling, the use of hydraulic fracturing technology.

» A change in regional transportation and infrastructure demands to allow for more rapid development of upstream assets.

Weakness in the price of natural gas has been a key driver of transaction flow in the Exploration and Produc-tion (E&P) sector. The upstream sector remains an area of high M&A activity in terms of the aggregate number of transactions, as represent-ed in Figure 2. Transaction volume has been led by shifting interests of diversified E&P operators, with divestitures attracting both indus-try buyers and private equity firms looking for undervalued businesses demonstrating cash flow generation, including in a joint venture format in certain instances. Seller motivations

FIGURE 1: OIL AND GAS M&A - SELECT SUB-SECTORS Transaction Volume - number of transactions (closed and/or effective)

Source: S&P Capital IQ LCD

0

50

100

150

200

250

300

2006 2007 2008 2009 2010 2011 2012

Oil and Gas Storage andTransportation

Oil and Gas Refining andMarketing

Oil and Gas Equipment andServices

Oil and Gas Drilling

3

January 2013

include a desire to prune non-core businesses from their existing port-folios, public company pressures to continue demonstrating growth from existing asset bases, pressures to di-vest assets and application of cash proceeds towards necessary capital expenditures, drilling activities, or paring of debt.

Recent declines in M&A activity re-flect a temporary sense of pause by acquirers. This slowdown in the number of transactions comes as a result of a need for buyers to fully integrate recently completed acquisi-tions, to evaluate the impact of global trends and secular shifts on future levels of demand, to interpret the consequences of energy price lev-els, and time for buyers to digest and consider the effects of possible future regulation and governmental policies.

Loan and High-Yield Fixed Debt Financings Provide Fuel for Heightened Transactional Activity

Banks and institutional investors have traditionally been key sources of capital for growth in the energy sector, most recently demonstrating a greater propensity to lend to oil and gas busi-nesses as part of a broader financing market recovery. Through the third quarter of 2012, more than 55 percent of the total loan volume for oil and gas investment was issued for growth purposes—including acquisition fund-ing, new investment activity, and proj-ect financing including investment in unconventional drilling activities as shown in Figure 3. Lender loan return expectations in the sector have reduced significantly relative to the 2008 reces-sion, indicating that capital supply is currently exceeding demand. For ex-ample, the cost of bank debt on trading debt is averaging 5-6 percent, substan-tially lower than the 9-10 percent range seen during the height of the recession.

FIGURE 3: OIL AND GAS LOAN VOLUME BY PURPOSE Q1 - Q3 2012

Source: S&P Capital IQ LCD

FIGURE 2: OIL AND GAS EXPLORATION AND PRODUCTION M&A Transaction Volume - number of transactions (closed and/or effective)

Source: S&P Capital IQ LCD

0

100

200

300

400

500

600

700

2006 2007 2008 2009 2010 2011 2012

Acquisition34%

Corp Purpose2%

DIP1%

LBO11%

Project Financing/Misc.

18%

Recap/Dividend2%

Recap/General Recap

0%

Refinancing32%

4

January 2013

Through the third quarter of 2012, more than $25 billion in loans and approximately $36 billion in non-in-vestment grade bonds were issued in the oil and gas sector, as indicated in Figures 4 and 5 respectively. This vol-ume is up sharply, compared to the aggregate of loans and bonds relative to prior years, reflecting increased market interest in the sector including supporting the unconventional drill-ing story backed by capital inflows and a thirst for yield, added to by virtue of a weak interest rate environ-ment driven by governmental mon-etary policies.

Past Cycles of Heavy Borrowing Have Been a Prelude to Increased Bankruptcies and Restructurings of Debt-Laden Businesses in the Sector

Sector trends demonstrate a cycle of high debt borrowing typically fol-lowed by increased business bank-ruptcies with a resulting need to restructure, sell, or liquidate. The significant debt provided by banks and other lending institutions prior to the 2008 recession was followed by an increased level of bankruptcies by entities exposed to natural gas market risks, as reflected in Figure 6.

The causes of financial distress were several, including:

» Lack of adequate planning for the extent of falling natural gas price dynamics. Many companies took a one-dimensional approach in their business planning efforts, with insufficient preparation for downside “what if” scenarios. Contingency planning and related stress case analyses would have been relevant planning measures but not adequately performed in the wake of a protracted weak natural gas pricing climate. Many E&P companies experienced significant contraction in their

semi-annual borrowing base redeterminations as a result of declining commodity prices, significantly reducing, or even eliminating required liquidity. Resulting business decisions were often reactive, sub-optimal, or focused on addressing immediate needs without considering longer-term planning perspectives.

» Secular shifts to shale and liquid-rich oil plays. During the early stages of the shale story, many believed the cyclicality of pricing would follow traditional patterns, restoring margins to historical levels, a judgment that left production and service companies exposed to significant market risk. Sector activity moved to emerging

FIGURE 5: OIL AND GAS NON-INVESTMENT GRADE BOND DEBT ISSUANCE Amount Issued ($ in Billions)

Source: Advantage Data

FIGURE 4: OIL AND GAS LOAN VOLUME Amount Issued ($ in Billions)

Source: Advantage Data

$0B

$5B

$10B

$15B

$20B

$25B

$30B

$35B

YTD 3Q2007

YTD 3Q2008

YTD 3Q2009

YTD 3Q2010

YTD 3Q2011

YTD 3Q2012

$0B

$5B

$10B

$15B

$20B

$25B

$30B

$35B

$40B

$45B

YTD 3Q2007

YTD 3Q2008

YTD 3Q2009

YTD 3Q2010

YTD 3Q2011

YTD 3Q2012

5

January 2013

shales in pursuit of drilling successes, however as technologies and techniques improved, the additional investment in equipment and staffing only contributed to additional financial pressures especially as the successes by drilling added to a sustained period of low gas prices. As natural gas drilling activity ultimately subsided on switching to oil directed drilling (in some cases to the minimum levels necessary to maintain leases) and moratoriums on drilling permits were put in place as the result of environmental impact reviews this caused demand for natural gas oilfield services to weaken.

» The fear of being left behind and execution missteps. Companies were enticed to become invested in the sector (attracted by the appeal of elevated natural gas prices without fully appreciating the investment thesis and its attendant risks). As a result of the exuberance to become involved, diligence was

compromised as evidenced by the demonstrated inability of many companies to effectively navigate the downturn. In addition, poor acquisition and post-merger integration activities by upstream oil and gas producers and many production services companies resulted in an inability to realize anticipated revenue enhancements and cost savings that were core to the investment thesis.

» Too much debt funding for cyclical businesses. By its nature, businesses exposed to natural gas can be cyclical and require appropriate levels of capital flexibility and prudent financial policies in order to “weather the storm” during severe market downturns. However the abundance of debt capital building leading up to 2008 was too attractive for many companies to pass up. This led to a surge in borrowing to fund purchases of equipment or drilling, acquisitions of businesses, or dividends paid to

business owners, but left limited “breathing room” once natural gas prices declined. Restrictions imposed by lenders, including natural gas commodity price hedges that were subject to potential termination in the event agreements with lenders were violated, also limited flexibility.

Investors Have Been Effective in Finding Value in the Sector

Business failures invariably create at-tractive opportunities. Despite chal-lenges, non-traditional and private equity investors have found particular appeal in acquiring businesses at low valuations or in providing capital in the sector at attractive returns, including:

» Buyers capitalizing on divestitures by E&P companies. Non-traditional buyers are capitalizing on the needs of diversified E&P companies to divest assets that are either non-core to their business strategy or to immediately generate cash. Due to the success in many instances of producing unconventional gas volumes, yet with the resulting decline in gas prices as a direct result of such successes, operators face liquidity constraints as they labor to sustain cash flow from lower priced production and in order to maintain lease acreage positions and other payments until gas prices increase. Several E&P companies have been active in selling gas reserves at historically low valuations, with aggressive and perhaps better capitalized buyers believing that acquiring these assets in the low commodity price “market trough” will yet allow for attractive returns over the longer term.

FIGURE 6: U.S. NATURAL GAS-RELATED BANKRUPTCIES

Source: Advantage Data

0

10

20

30

40

50

60

2007 2008 2009 2010 2011 2012

Num

ber o

f Ban

krup

tcy F

ilings

6

January 2013

» Lenders disinterest in assuming long-term ownership stakes. As a result of the difficulties experienced by the E&P companies, lenders have taken ownership of businesses in the sector through bankruptcies, foreclosures, and consensual handovers—with investors playing to lender motivations for clean and quick transactions. In assessing the relationship between the company and its lender base, this can shed light on whether or not lenders will continue to serve as partners for business, including those acquired through bankruptcy or by other means, thus determining the extent of support lenders will provide or, alternatively, creating the opportunity to acquire assets from highly motivated lenders focused on near-term exits.

» Investors buying debt trading at significantly low levels with an ownership strategy through a business restructuring. Activist lenders are prepared to take over assets through a foreclosure or bankruptcy. In a recent situation, lenders acquired a business as the incumbent private equity owner was unwilling to reinvest, believing that the business was poorly positioned for the secular shifts in shale drilling activity. Activist funds bought the business debt at levels significantly below face value, recapitalized it, and emerged as new owners through a formal restructuring. This business subsequently recovered meaningfully through a refined strategy, new board, and repositioning for shale activity, resulting in a substantial financial return to the activist lenders.

» Operators requiring equity or less rigid debt capital to address deficiencies in their working capital facilities. As is often the case, companies operating in the gas sector may carry too much debt and as a result face problems due to sustained low gas prices, or other operational challenges causing them to continue to turn to non-traditional and expensive sources of capital when commercial banks and other capital market lenders turn them down. If this strategy is not successful, the Chapter 11 bankruptcy route can provide an avenue for financing or acquisition of liabilities-free assets, with minimized challenges to the sale, and relatively straight forward assignment of key contracts, albeit on less optimal terms.

Fundamental shifts in the natural gas sector in North America have drawn interest from capital provid-ers, in both the unconventional gas and oil industries. Generally down-ward trending gas commodity prices since 2009 have enticed buyers and financiers of attractively priced natu-ral gas-related assets and redirected new capital and industry resources to unconventional oil and wet gas. The recent surge in the supply of debt financing commencing in 2010 and the recent volume of debt be-ing placed on companies in the sec-tor is a catalyst for the next round of winners and losers in the sector. What may follow this recent surge in capital investment may be the next phase of increased distress in the sec-tor as a result of failing producers, underutilized service providers, and infrastructure asset owners carrying

excess capacity. As a caution, own-ers, operators and asset managers are best advised to apply prudent finan-cial measures to their businesses with a goal of maximizing financial flexi-bility. This is to enable the business to be adequately capitalized in the event that a low priced natural gas environ-ment endures for an extended period of time, or more recent investments in liquid-rich leasehold positions or related businesses do not achieve forecasted levels of success. Measures should include a process of match-ing a suitable level and profile of debt to assets exposed to cyclical natural gas related markets, and ensuring that sufficient liquidity is in place to fund necessary operations, capital for drilling programs, and growth. The alternative outcome, as demonstrated in the past, is unexpected and swift lender-driven curtailment of critical liquidity as well as defensive lender actions creating a significant diminu-tion in value that oftentimes inures to the benefit of third-party investors. Proactive decision-making, long-term scenario planning, and forward thinking should help to alleviate the number of risks and facilitate optimal value outcomes.

— Raoul Nowitz

The opinions expressed in this article are those of the authors and do not necessarily represent the views of Navigant Consulting, Inc.

About the Author » Raoul Nowitz serves as a Director with Navigant Capital Advisors, Navigant’s corporate finance arm, where he focuses on providing restructuring advisory services and solutions, mergers and acquisitions advisory services, and capital raisings to middle market companies in a variety of industries. Assistance in this article was provided by other members of Navigant Capital Advisors team including Greg Hagood, Kim Brady, and George Koutsonicolis.

7

January 2013

Natural Gas Market Charts

MONTHLY GAS INDEX PRICE

$0

$2

$4

$6

$8

$10

Dec-10 Apr-11 Aug-11 Dec-11 Apr-12 Aug-12 Dec-12

$/M

MB

tu

Chicago Opal New YorkAECO-C SoCal Gas Henry Hub Sources: Navigant/Gas Daily

Monthly index gas prices continued rising last month, with Henry Hub increasing 7% to $3.71/MMBtu for December from $3.47 for November.

NYMEX FUTURES SETTLEMENT PRICES AT CLOSE

$3

$4

$5

Nov-12 Feb-13 May-13 Aug-13 Nov-13

$/M

MB

tu

Sources: Navigant/NYMEX

Nov

DecJan

The average 12-month strip price decreased to $3.58/Mmbtu from $3.85.

DAILY GAS PRICE

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

$22

Dec-10 Apr-11 Aug-11 Dec-11 Apr-12 Aug-12 Dec-12$/

MM

Btu

Chicago Opal New YorkAECO-C SoCal Gas Henry Hub

Sources: Navigant/Gas Daily

The daily spot prices ended the month down 6% from November, with Henry Hub at $3.41/MMBtu.

MONTHLY PRICES: OIL AND NATURAL GAS GULF COAST

$0

$6

$12

$18

$24

Nov-08 Nov-09 Nov-10 Nov-11 Nov-12

$/M

MB

tu

WTI (Cushing, OK), Crude Oil

Henry Hub - Natural Gas Sources: Navigant / Platts

Most recent comparison shows a narrowing but still large monthly price spread, with Henry Hub natural gas price at $3.71 versus WTI crude oil price at $13.77, an equivalent energy ratio of 3.7 times.

8

January 2013

Natural Gas Market Charts

U.S. DRY GAS PRODUCTION

52

54

56

58

60

62

64

66

68

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Bcf

/day

2009 2010 2011 2012Sources: Navigant / EIA

U.S. dry gas production continues above 66 Bcfd.

U.S. WEEKLY NATURAL GAS RIG COUNT

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Rig

s

2008 2009 2010 2011 2012

Sources:Navigant/ Baker Hughes

Jan OctSepAugJulJunMayAprMar DecNovFeb

U.S. natural gas rig count rose to 432, its highest level in 12 weeks.

U.S. WELLHEAD SHALE GAS PRODUCTION

0

5

10

15

20

25

30

Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12B

cf/d

ay

Marcellus Eagleford WoodfordFayetteville Haynesville Barnett ShaleOther

Sources: Navigant/ LCI

Total U.S. shale gas production continues to increase, to just over 29 Bcfd.

U.S. GAS STORAGE

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

Bcf

Range (2002-2011) 2008 20092010 2011 2012

Jan OctSepAugJulJunMayAprMar DecNovFeb

Sources: Navigant / EIA

U.S. storage levels continue strong, moving to 3% above the top of the 10-year range for December.

9

January 2013

Natural Gas Market Charts

CANADA GAS STORAGE

50

150

250

350

450

550

650

750

Bcf

Range (2006-2011) 2008 20092010 2011 2012

Sources: Navigant / Enerdata

Jan OctSepAugJulJunMayAprMar DecNovFeb

Canadian storage inventories are following seasonal patterns at the top of the 5-year norm for this time of year.

U.S. TEMPERATURE OUTLOOK

The temperature outlook is for above normal temperatures for most of the southern U.S., and for below normal temperatures for most of Montana and North Dakota.

U.S. MONTHLY NATURAL GAS DEMAND

40

50

60

70

80

90

100

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecB

cf/d

2008 2009 2010 2011 2012Sources: Navigant / EIA

Demand is showing a normal seasonal increase, and exceeds the average level of the prior four years at this time by about 8%.

NAVIGANT PRICE PREVIEW

Price forecasts average about $3.75 for 2013.

Source2013 Price Forecast (Nominal $/MMBtu)

EIA $3.68Barclay’s $3.70Goldman $4.25Survey Average $3.88Navigant $3.45

Sources: Navigant Survey/Navigant

10

January 2013

Legislative and Regulatory Highlights

National

DOE-Commissioned Study on Macroeconomic Impacts of LNG Exports Released

On December 5, the U.S. Department of Energy’s Office of Fossil Energy posted the final version of the DOE-commissioned report by NERA Economic Consulting entitled “Macroeconomic Impacts of LNG Exports from the United States.” The report is the second of two LNG export studies ordered by DOE; the first was the Energy Information Administration price impact report from January 2012. The NERA report found that across all modeled scenarios, “the U.S. was projected to gain net economic benefits from allowing LNG exports. More-over, for every one of the market scenarios examined, net economic benefits increased as the level of LNG exports increased.” Further, the NERA report concluded that the assumed LNG export levels specified in the EIA study often would not actually be feasible in the global market because “in many cases, the world natural gas market would not accept the full amount of exports assumed in the EIA scenarios at export prices high enough to cov-er the U.S. wellhead domestic prices calculated by the EIA.” Initial comments on the NERA report are due by January 24, 2012.

EPA Issues Progress Report on its Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources

On December 21, the U.S. Environmental Protection Agency issued a Progress Report on its Study of the Potential Impacts of Hydraulic Fracturing on Drink-ing Water Resources, which was requested by Congress in 2009. The Progress Report describes the 18 research projects currently underway to help answer questions around the five stages of the hydraulic fracturing water cycle: water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and waste disposal. The research projects are grouped according to the following five research activities: 1) analysis of existing data, including chemical and water use at thousands of wells; 2) computer models to analyze scenarios of subsurface gas and fluid migration, large volume water withdrawals, and surface water transport of treated wastewater; 3) laboratory studies on such mat-ters as the effectiveness of common wastewater treatment processes on hydraulic fracturing wastewater, the forma-tion of disinfection byproducts, and the effectiveness of analytical detection methods; 4) toxicity assessments of chemicals found in flowback and produced water; and 5) case studies based on sampling near well sites. The report indicates that a draft study should be available for public and peer review in 2014.

11

January 2013

Northeast/Appalachia

Williams Partners’ Transco Pipeline Seeks FERC Approval for Virginia Southside Expansion

Williams Partners’ Transco pipeline announced on December 19 its filing with FERC for approval to build its Virginia South-side Expansion project, designed to provide about 270 MMcfd of incremental natural gas transportation capacity to serve markets in Virginia and North Carolina. The $300 million project would consist of about 100 miles of 24-inch pipeline to provide 20 MMcfd capacity to Piedmont Natural Gas Compa-ny and 250 MMcfd capacity to Dominion Virginia Power.

Dominion and Caiman Energy II Announce Utica Shale Joint Venture

On December 20, Dominion and Caiman Energy II an-nounced their formation of a 50-50 joint venture to pro-vide midstream services to natural gas producers oper-ating in the Utica shale in Ohio and Pennsylvania. Blue Racer Midstream LLC will provide gathering, processing, fractionation, and NGL transportation and marketing ser-vices. The venture will leverage Dominion’s existing as-sets in the Utica with $800 million in funding by Caiman, potentially creating 2 bcfd of gathering capacity.

Gulf Region

Cheniere and Total Sign 20-Year Supply Contract from Planned Fifth LNG Train at Sabine Pass

On December 17, Cheniere Energy Partners announced that its subsidiary, Sabine Pass Liquefaction, entered into an LNG supply contract with Total Gas & Power North America Inc. to supply about 100 bcf per year of LNG from a fifth liquefac-tion train planned for the project. The 20-year commitment to Total represents almost half the annual capacity of the ad-ditional train, which could be in service as early as 2018.

Cheniere and Bechtel Sign Turnkey Contract for Liquefaction Trains 3 and 4 at Sabine Pass

On December 21, Cheniere Energy Partners announced that its subsidiary, Sabine Pass Liquefaction, entered into a $3.8 billion lump sum turnkey contract for the engineer-ing, procurement and construction of the third and fourth liquefaction trains to be built adjacent to Cheniere’s Sa-bine Pass LNG terminal in Cameron Parish, Louisiana. A final investment decision and beginning of construction is expected in the first half of 2013. Bechtel began con-struction on the first two trains in August 2012.

California/Pacific Northwest

CPUC Approves Pipeline Safety Plan for PG&E, But Disallows more than 60 percent of Cost RecoveryCPUC Docket R.11-02-019; Decision D.12-12-030

On December 20, the California Public Utilities Commis-sion issued a decision approving Pacific Gas and Electric Company’s 2012-2014 Pipeline Safety Implementation Plan, under which PG&E will be required to pressure test 783 miles of natural gas pipeline, replace 186 miles of pipeline, upgrade 199 miles of pipeline to allow in-line inspection, and install 228 automated shut-off valves. However, the CPUC authorized only 39 percent of the funds PG&E requested, approving $299 million for the three-year period; due to past deficiencies, PG&E share-holders will bear the costs of pressure testing pipeline for which test records are missing and the costs of the record management improvement project. Due to PG&E’s past management decisions that led to the need to under-take the massive safety project on an expedited basis, the CPUC required that PG&E shareholders bear the risk of cost overruns.

FERC Authorizes Construction of GTN’s Proposed Carty Lateral ProjectFERC Docket No. CP12-494-000

FERC’s Office of Energy Projects authorized Gas Trans-mission Northwest LLC’s request to construct a 24-mile, 20-inch natural gas pipeline in Morrow County, Oregon to provide up to 175 MMcfd of delivery capacity to Port-land General Electric Company’s planned Carty Gener-ating Station. The new lateral will begin at the existing GTN mainline system at Ione, Oregon, and terminate at the new power plant 13 miles southwest of Boardman, Oregon. The proposed in-service date is November 2014.

12

January 2013

National

Government Approves Acquisition of Progress Energy by Malaysia’s Petronas

Petronas, the national oil and gas company of Malaysia, and Progress Energy Resources Corporation announced on December 9 the approval by the Government of Canada’s Ministry of Industry of Petronas’ acquisition of Progress. Petronas plans to combine its LNG develop-ment experience with Progress’ unconventional resource development experience to help move forward its Pacific Northwest LNG project on Lelu Island near Prince Ru-pert. A final investment decision is expected in late 2014, with first LNG exports expected 2018.

Conference Board Report Forecasts Doubling of Canadian Natural Gas Demand

On December 17, the Conference Board of Canada issued a report entitled “The Role of Natural Gas in Powering Canada’s Economy” that forecast a doubling of Cana-dian demand for natural gas between 2012 and 2035 (with most of the gain reached by 2025). The report cites three factors for the increase: increasing production from Alberta’s oil sands, increasing use of electric generation in Alberta and Ontario, and exports of LNG from Brit-ish Columbia. The report also estimates that most of the new demand will be met through declines in Canadian exports of natural gas to the U.S.

Alberta

Encana Announces Joint Venture with Chinese Firm to Develop Duvernay Shale

On December 13, Encana Corporation announced that it entered into a joint venture with Phoenix Duvernay Gas, a subsidiary of PetroChina, to explore and develop 445,000 acres in the Duvernay play in west-central Alber-ta. Phoenix paid C$2.18 billion for a non-controlling 49.9 percent interest in the lands, with $1.18 billion in cash at close and $1 billion to fund 50 percent of development capital over the next four years. Encana will remain as operator of the joint venture.

British Columbia

Chevron and Apache to Partner on Kitimat LNG Project

On December 24, Apache Corporation announced that it signed a joint venture agreement with Chevron Canada Limited to build and operate the proposed Kitimat LNG export terminal project. As part of the deal, EOG Re-sources and Encana, both 30 percent owners of Kitimat LNG, sold their shares to Chevron, while Chevron and Apache agreed to a 50-50 partnership for not only the Kitimat LNG project, but also the 290-mile Pacific Trail Pipeline and 644,000 acres in the Horn River and Liard basins. Chevron will operate the LNG facility, while Apache will operate the upstream assets. The agreement is intended to capitalize on Chevron’s LNG development and marketing expertise, as well as on Apache’s up-stream operating experience.

13

January 2013

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CHALLENGECHALLENGE

CHALLENGE

NORTH AMERICAN NATURAL

GAS SUPPLY ASSESSMENT

CHENIERE: LNG EXPORT

IMPACT ASSESSMENT

DOMINION: LNG EXPORT

IMPACT ASSESSMENT

SOLUTION

SOLUTION

SOLUTION

In 2008, Navigant released the first

major study of North American natu-

ral gas supply recognizing the poten-

tial for shale gas development. At a

time when the conventional wisdom

was that U.S. natural gas was a de-

clining resource, Navigant defied

the status quo and supported a fifty

percent increase over the then-pre-

vailing resource estimates. Today,

the prevailing estimates resemble

Navigant’s initial, ground breaking

evaluation from 2008, with natural

gas abundance being widely ac-

knowledged. Gas shale production

has been robust enough for LNG im-

ports to be replaced by LNG exports.

Navigant experts played a substan-

tial role in beginning North America’s

natural gas transformation.

Navigant provided a detailed as-

sessment and analysis of the U.S.

gas market impact of LNG exports,

for Cheniere Energy’s Department

of Energy (DOE) export application

for its Sabine Pass, Louisiana export

project. Navigant conducted the

analysis with its proprietary industry-

leading market model built upon

the Gas Pipeline Competition Model

(GPCM) and its expert analysis was a

key component of Navigant’s report

in support of the project. The appli-

cation for export by Cheniere is at

this time the first and only LNG export

project to have received DOE ap-

proval to non-Free Trade countries.

In support of Dominion’s application

to DOE for LNG long term export au-

thority to non-Free Trade countries,

Navigant provided a report assess-

ing the U.S. gas market impact of

exports from Dominion’s Cove Point,

Maryland facility. Navigant’s assess-

ment of the U.S. natural gas market,

including the Marcellus gas shale

basin, was captured in the market

and infrastructure reports provided

to the client. Both reports and the

analysis were based upon Navi-

gant’s leading North American

market model built upon GPCM,

and were filed in support of Domin-

ion’s LNG export application in

September 2011.

E n E r g y

Natural Gas Market Modeling and Scenario Analysis