1. Conference Call to Review
2006 Fiscal Year and Fourth Quarter
Financial Results
November 8, 2006
8:00 a.m. EST
2. Forward Looking Statements
The matters discussed or incorporated by reference in this presentation may contain
“forward-looking statements” within the meaning of Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than
statements of historical fact included in this presentation are forward-looking statements
made in good faith by the Company and are intended to qualify for the safe harbor from
liability established by the Private Securities Litigation Reform Act of 1995. When used
in this presentation or in any of the Company’s other documents or oral presentations,
the words “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “goal,” “intend,”
“objective,” “plan” “projection,” “seek,” “strategy” or similar words are intended to identify
forward-looking statements. Such forward-looking statements are subject to risks and
uncertainties that could cause actual results to differ materially from those discussed in
this presentation, including the risks relating to regulatory trends and decisions, the
Company’s ability to continue to access the capital markets and the other factors
discussed in the Company’s filings with the Securities and Exchange Commission. These
factors include the risks and uncertainties discussed in the Company’s Annual Report on
Form 10-K for the fiscal year ended September 30, 2005, and the Company’s Quarterly
Report on Form 10-Q for the three and nine months ended June 30, 2006. Although the
Company believes these forward-looking statements to be reasonable, there can be no
assurance that they will approximate actual experience or that the expectations derived
from them will be realized. The Company undertakes no obligation to update or revise
any forward-looking statements, whether as a result of new information, future events or
otherwise.
Further, the Company will only update earnings guidance through its quarterly and
annual earnings releases. All estimated financial metrics for fiscal year 2007 and beyond
that appear in this presentation are current as of the date noted on each relevant slide. 2
3. Consolidated Financial Results – Fiscal 2006
Key Drivers
Net Income
Increased contribution from
nonutility businesses, primarily
natural gas marketing segment, due
to higher margins and market
volatility
$162.3 Rate increase adjustments, primarily
$170.0 20 %
GRIP in Texas effective in 2006
$160.0 $147.7 Nonrecurring, noncash charge of
9% $14.6 million due to impairment of
$150.0 $135.8 irrigation properties in West Texas
$140.0 Weather was 13% warmer than
normal and 2% warmer than the
$130.0 prior year, as adjusted for
jurisdictions with weather-
$120.0 normalized rates
$110.0 Increase in O&M expenses due to
2005 2006 2006 (excl. higher employee-related costs
charge) Increase in interest expense due to
higher S-T Debt balances and
($ in millions) interest rate increases
3
4. Consolidated Financial Results – Fiscal 2006
Earnings per Diluted Share
Notes
2006 includes $0.18 per diluted
$2.00
share related to nonrecurring,
16%
$2.00 noncash charge for
impairment of irrigation
$1.82
6%
properties in utility segment
$1.72
$1.75 Delivered on company’s 2006
guidance range of $1.80-$1.90
per diluted share, despite 13%
warmer than normal weather
$1.50
Period-over-period increase of
almost 2.4 million weighted
average diluted shares
$1.25
outstanding
2005 2006 2006 (excl.
charge)
4
5. Consolidated Financial Results – Fiscal 2006
Net Income by Segment
81.1
$90.0
58.6
$75.0
53.0
($ in millions)
$60.0
35.6
$45.0 30.6
23.4
$30.0
0.5
0.7
$15.0
$0.0
2005 2006
Utility Natural gas marketing
Pipeline and storage Other nonutility
5
6. Consolidated Financial Results – Fiscal 2006
Drivers
$98.9 million increase in gross profit
$17.7 million increased utility gross profit primarily from
o $22.9 million decrease primarily due to decreased throughput of 17.1
Bcf, due to weather that was 2 percent warmer than the prior year
o $16.1 million increase related to higher franchise fees, higher state
gross receipts taxes paid and other items
o $13.8 million increase due to rate adjustments resulting from the
GRIP-related recovery for 2004 and 2005 capital expenditures in
Texas
o $6.2 million increase due to recognition of previously deferred revenue
associated with 2003 Rate Stabilization Filing with the Louisiana
Public Service Commission
o $2.9 million decrease due to the impact of Hurricane Katrina
6
7. Consolidated Financial Results – Fiscal 2006
Jurisdictions Adjusted for WNA
At September 30, 2006, we had WNA in the following service areas for
the following periods as noted, which covers over 90% of our customer
meters in service:
Tennessee November – April
Georgia October – May
Mississippi November – April
Kentucky November – April
Kansas October – May
Louisiana * December – March
Mid-Tex * October – May
Amarillo, TX October – May
October – May
West Texas
Lubbock, TX October – May
January – December
Virginia
* New for the 2006-2007 winter heating season
7
8. Consolidated Financial Results – Fiscal 2006
YTD Warmer than Normal Weather Effect by Division
ted
s
i da
a
ate ky s
ia n
xa ex
S ol
tuc
St
/K Te uis d- T s
d- n n
W.
MS Mi Mi
CO Ke Co
Lo
10
• Fiscal 2006 utility
gross profit was
Percent (Warmer) Colder than Normal
adversely affected
2%
0% 0% by $49.2 million due
0 to weather that was
13% warmer than
1%
normal, as adjusted
for jurisdictions with
5%
weather-normalized
7%
rates
(10)
9% 10%
9%
• Louisiana and Mid-
Tex Divisions did
13%
not have weather-
15%
normalized rates and
18% experienced warmer
(20)
than normal weather
of 22% and 28%,
22%
respectively
28%
(30)
Actual / Normal Adjusted for WNA
8
9. Consolidated Financial Results – Fiscal 2006
Relationship of Utility EPS to Heating Degree Days
Degree Days
EPS (Adjusted for WNA)
$1.25 3,500
$1.16
3,271 $1.03
3,250
$1.00
$0.83 *
3,000
$0.75
2,587
2,750
2,527
$0.50
2,500
$0.25 2,250
2004 2005 2006
* Excludes negative impact of asset impairment
9
10. Consolidated Financial Results – Fiscal 2006
Utility Margin Sensitivity
2004–2006 2006–2007E
2003–2004
Heating Season
Heating Seasons
Heating Season
(Post-TXU Gas)
(Before TXU Gas)
9%
5%
35%
36%
48%
51%
86%
13% 17%
Weather Weather- Nonweather-
Normalized Sensitive Margin Sensitive Margin*
* Non-weather sensitive margin is gas consumption not correlated to weather, i.e., gas clothes dryer, gas water heater,
gas cooking, and includes monthly fixed charge
10
11. Consolidated Financial Results – Fiscal 2006
Drivers
$98.9 million increase in gross profit (continued)
$68.6 million increase in natural gas marketing gross profit primarily
due to
o $27.3 million increase in realized marketing margins primarily due
to increased volumes sold of 45.9 Bcf year over year and capturing
higher margins in certain market areas that experienced increased
volatility
o $1.8 million decrease in realized storage contribution as a result of
unfavorable arbitrage spreads related to storage optimization
efforts, coupled with increased storage fees on incremental
storage capacity added in the third quarter of fiscal 2005
o $12.7 million decrease in unrealized storage mark-to-market
losses primarily due to favorable movement between the forward
prices used to value financial hedges and the spot prices used to
value the physical storage positions, coupled with an increase in
physical storage positions of 7.6 Bcf year over year
o $30.4 million increase in unrealized marketing mark-to-market
gains primarily due to favorable movement in the forward prices
used to value the financial derivatives used in these activities 11
12. Consolidated Financial Results – Fiscal 2006
Year Ended September 30
Natural Gas Marketing Segment 2006 2005 Change
(In thousands, except physical position)
Storage Activities
Realized margin $26,225 $28,008 ($1,783)
Unrealized margin (1,293) (14,007) 12,714
Total Storage Activities 24,932 14,001 10,931
Marketing Activities
Realized margin 87,236 59,971 27,265
Unrealized margin 18,459 (11,999) 30,458
Total Marketing Activities 105,695 47,972 57,723
GROSS PROFIT $130,627 $61,973 $68,654
Net physical position (Bcf) 14.5 6.9 7.6
12
13. Consolidated Financial Results- Fiscal 2006
Fair Value of Contracts at September 30, 2006
Maturity in Years
Total Fair
Source of Fair Value <1 1-3 4-5 >5 Value
(In thousands)
$ — $ — $ (10,299)
Prices actively quoted $ (17,421) $ 7,122
Prices provided by other
—
external sources (440) (936) — (1,376)
Prices based on models &
other valuation methods (255) (276) — — (531)
$ $ — $ (12,206)
—
Total Fair Value $ (18,116) $ 5,910
13
14. Consolidated Financial Results – Fiscal 2006
Drivers
$98.9 million increase in gross profit (continued)
$13.2 million increase in pipeline and storage gross
profit primarily due to
o $16.2 million increase due to a 34.9 Bcf increase
in total transportation volumes, higher
transportation & related service margins and
more favorable arbitrage spreads captured in
asset management contracts, partially offset by a
o $3.0 million decrease due to the absence of
inventory sales realized in the prior year
14
15. Consolidated Financial Results – Fiscal 2006
Drivers
Increased O&M expenses of $17.1 million primarily
due to
$19.6 million increase in employee costs associated
with increased headcount and benefit costs primarily
resulting from changes in the pension assumptions
used to determine the fiscal 2006 costs
$2.1 million decrease due to the absence of UCG
acquisition-related M&I costs which became fully
amortized in fiscal 2005
$1.5 million increase in provision for doubtful
accounts due to due to increased collection risk on
higher customer bills caused by higher gas prices
15
16. Consolidated Financial Results – Fiscal 2006
Pension, Post-Retirement & Other Benefits Expense
(in millions)
$53.3 Other
$60.0
Medical & Dental
$44.1
$50.0 9.3 Post-Retirement
Pension
$40.0 9.9
20.1
$30.0
16.7
2006 Pension Assumptions
$20.0 14.2 8.50% return on plan assets
5.00% discount rate
12.8
$10.0 4.00% wage increase
9.7
4.7
$0.0
2005 2006
16
17. Consolidated Financial Results – Fiscal 2006
Utility Bad Debt Expense as a Percent of Revenues
2.0 1.86
1.5
Percent
1.0 0.83
0.58 0.58
0.5 0.29
0.0
0.0
2001 2002 2003 2004 2005 2006
17
18. Consolidated Financial Results – Fiscal 2006
Drivers
Increased taxes, other than income, of $17.3 million primarily due to
increased franchise fees and state gross receipts taxes
Increased operating expenses due to $22.9 million noncash charge to
recognize the impairment of West Texas irrigation properties in fiscal 2006
Increased interest charges of $13.9 million
$18.7 million increase primarily due to higher short-term debt
balances used for natural gas purchases made at significantly higher
prices coupled with an increase in the 3-month LIBOR rate, partially
offset by
$4.8 million decrease in interest charges from the early payoff of
$72.5 million of First Mortgage Bonds in June 2005
Decreased miscellaneous income of $1.1 million due to $3.3 million
noncash charge in fiscal 2006 related to an adverse regulatory ruling in
Tennessee associated with gas purchases and the PBR calculation
18
21. Consolidated Financial Results – Fiscal 2006 4Q
Net Income (Loss)
Key Drivers
Increase in natural gas marketing
$20.9 margins, primarily unrealized
$25.0
marketing and storage margins
$15.0 $6.1 Nonrecurring, after-tax charge of
$14.8 million due to impairment of
$5.0
irrigation properties in West Texas
($5.0)
Rate increases associated with
Texas GRIP
($15.0)
($16.8)
Increased interest expense due to
($25.0)
higher average short-term debt
4Q 2005 4Q 2006 4Q 2006
balances and an increase in the 3-
(excl. month LIBOR rate
charge)
($ in millions)
21
22. Consolidated Financial Results – Fiscal 2006 4Q
Net Income (Loss) per Diluted Share
Notes
$0.40 $0.25
Includes a nonrecurring, after-
$0.20 tax charge due to impairment
$0.07
of irrigation properties in West
Texas Utility Division of $0.18
$0.00
per diluted share
Quarter-over-quarter increase
($0.20)
($0.21) of approximately 1.7 million
weighted average diluted
($0.40)
shares outstanding
Q4 2005 Q4 2006 Q4 2006
(excl.
charge)
22
25. Highlights – Fiscal 2006
Natural Gas Gathering Project (map in appendix)
May 10, 2006, announced plans to construct 60-mile, 20-
inch natural gas gathering system in eastern Kentucky
Expected to relieve severe pipeline constraints and
accommodates rapidly expanding production in the region
(Big Sandy)
Estimated project cost is $75-$80 million
An independent producer in the area will have ownership
interest in the project
Project received exemption from regulatory oversight by
the Federal Energy Regulatory Commission in early
October; other required regulatory approvals pending
Anticipate construction to begin in the first half of fiscal
2007, and operations to begin in fiscal 2008
25
26. Highlights – Fiscal 2006
Louisiana Rate Settlement
May 25, 2006, Louisiana Public Service Commission (LPSC) approved
settlement of several existing dockets
Allows modified WNA which provides for partial decoupling
Renews the Rate Stabilization Clause (RSC) with provisions reducing
regulatory lag and a refund of $400,000
First RSC filing for the LGS service area made in August 2006,
with an effective date of August 12, 2006, based on a test year
ended December 31, 2005
First RSC filing for the Trans La service area should be made by
December 31, 2006, for the test period ending September 30,
2006, with effective date of April 1, 2007
WNA in both service areas will be effective for an initial three year
period beginning with the 2006-2007 winter
Implemented new rates subject to refund in September 2006, reflecting
reduction of about 26,500 customers and recovery of costs as a result of
damage related to Hurricane Katrina 26
27. Highlights – Fiscal 2006
Rate Case Filing in Mid-Tex Division
May 31, 2006, filed for rate increase of $60 million and
several rate design changes including WNA, Revenue
Stabilization, and recovery of the gas cost component of bad
debt
July 6, 2006, an interim agreement was reached to implement
WNA effective October 1, 2006
Interim WNA uses 30 years of weather history and permanent
WNA will allow the parties to contest the period of weather
data used to calculate normal weather
Hearing is currently in progress and expected to continue
through November 15, 2006
Anticipate decision on the case by April 2007
Any rate increase will be effective from the day of final order;
any rate decrease will be effective from May 31, 2006
Affects approximately 1.5 million customers in Texas 27
28. Highlights – Fiscal 2006
Mid-Tex Division Rate Case – Proposed Schedule
2006 2007
Event September October November December January February March April
Last Day to File 9/15/06
Discovery in Company’s
Direct Case
10/3/06
Staff and Intervenor
Direct Testimony
10/24/06
Company Rebuttal
Hearing on the Merits 10/31/06
BEGINS
11/15/06
Hearing on the Merits
CONCLUDES
11/28/06
Initial Briefs Due
12/7/06
Reply Briefs Due
1/8/07
Proposal for Decision
(PFD) Issued
1/23/07
Exceptions Due
1/30/07
Replies to Exceptions
First Possible RRC 2/6/07
Conference (Oral
Argument)
4/2/07
Second Possible RRC
Conference (Decision)
28
29. Highlights – Fiscal 2006
GRIP Filings – State of Texas
April 13, 2006, Atmos Pipeline-Texas 2005 GRIP filing of $3.3 million
revenue increase related to return and capital-related expenses on $21.6
million in net investment during calendar 2005, implemented August 2006
March 31, 2006, Mid-Tex Division 2005 GRIP filing of $11.8 million related
to return and capital-related expenses on $62.1 million increase in net
investment during calendar 2005; implemented September 2006
September 2005, Mid-Tex Division 2004 GRIP filing of $6.7 million related
to return and capital-related expenses on $29.4 million increase in net
investment during calendar 2004, implemented Feb. 2006
September 2005, Atmos Pipeline-Texas 2004 GRIP filing of $1.9 million
revenue increase related to return and capital-related expenses on $10.6
million in net investment during calendar 2004, implemented January 2006
September 2005, West Texas Division 2004 GRIP filing for $3.8 million on
increase in net investment of $22.6 million
Implementation of new charges in January 2006, except for the inside city limits
customers, which went into effect in May 2006.
29
30. Highlights – Fiscal 2006
GRIP Filing Process in Texas
Effective Immediately
ACCEPT
60 Effective under “Operation of Law”
IGNORE
days
Atmos files
with cities
Atmos appeals
to RRC within
DENY Up to
30 days
105
days
RRC
SUSPEND
Rules
45
days
30
31. Highlights – Fiscal 2006
Rate Case Filing – Missouri
April 7, 2006, filed request for 1st rate increase in over
9 years in Missouri
Request for revenue increase of about $3.4 million, or
5.9%
Total company investments approximate $22.0 million
over the 9-year period
Currently in settlement discussions with commission
Serve approximately 60,000 residential, commercial
and industrial customers in Missouri
31
32. Highlights – Fiscal 2006
Rate Case Result – Tennessee
November 2005, Tennessee Regulatory Authority
(TRA) began investigation into allegations by the
Consumer Advocate’s Office of the Tennessee
Attorney General’s Office that Atmos Energy was
overcharging customers by approximately $10 million
On October 27, 2006, the TRA voted to reduce rates
by $6.1 million, effective December 1, 2006
We are currently analyzing the timing of a new rate
case filing
Serve approximately 125,000 residential, commercial
and industrial customers in Tennessee
32
33. Highlights – Fiscal 2006
Rate Stabilization Results - Mississippi
October 3, 2005, Mississippi Public Utilities Staff reached an agreement with the
Mississippi Division of Atmos Energy, requiring an up-front rate reduction of
$600,000 effective October 1, 2005 and the following revisions:
Annual filings to be made, effective November 1 each year, effective September 5,
2006
New earnings sharing mechanism established
50/50 sharing of all earnings above allowed ROE for the first year
Thereafter, Atmos allowed to retain up to 250 additional basis points above ROE
Calculated ROE plus a performance adjuster of up to 50 basis points (currently
9.8%)
Shifts $10 million in annual margins from volumetric to customer charge
Revised WNA to include approximately 4% of additional heating degree days
Reduces regulatory lag, adjusts for forward-looking known and measurable
expenses and utilizes an average expected rate base
Changes affect approximately 251,000 customers
33
35. Highlights – Fiscal 2006
Credit Facilities
November 7, 2006, Atmos Energy entered into a new $300
million, 364-day committed revolving credit facility
Supplements amounts available under existing $18 million
committed credit facility and $25 million uncommitted credit facility,
under essentially the same terms as the $600 million 3-year
committed revolving credit facility
April 1, 2006, Atmos Energy renewed its existing $18
million committed credit facility, with no material changes to
terms and pricing
November 28, 2005, Atmos Energy Marketing (AEM)
increased its $250 million uncommitted credit facility to
$580 million, with essentially same terms
On March 31, 2006, AEM subsequently amended and extended
this facility to March 31, 2007
On October 18, 2005, Atmos Energy entered into a $600
million, 3-year committed revolving credit facility through
October 18, 2008, which serves as a backup liquidity
facility for our commercial paper program 35
37. Highlights – Fiscal 2006
Annual Dividend Increase
19th consecutive annual dividend increase
92nd consecutive dividend declared
1.6 percent annual increase from $0.315 per share to
$0.32 per share each quarter
Indicated annual dividend of $1.28 per share
To be paid on December 11, 2006, to shareholders of
record on November 27, 2006
37
39. Consolidated Financial Results – Fiscal 2007E
Earnings Guidance – Fiscal 2007E
Atmos Energy anticipates earnings to be in the range of
$1.90 - $2.00 per fully diluted share for the 2007 fiscal year
Assumptions include:
• Contribution from natural gas marketing segment reflects less
volatility in gas prices
o Total expected gross margin contribution from the marketing segment in
the range of $75 million to $85 million, including $10 million positive
mark-to-market impact
• Continued execution of rate strategy and collection efforts
• Normal weather in non-WNA jurisdictions
• Bad debt expense of no more than $22 million
• Average short-term interest rate @ 6.3%
• No material acquisitions
Note: Changes in these events or other circumstances that the company cannot currently anticipate could
materially impact earnings, and could result in earnings for fiscal 2007 significantly above or below this outlook.
39
41. Consolidated Financial Results – Fiscal 2007E
Atmos Energy Marketing – Gross Profit Margin Composition
2007E
Impacted by customer volume demand
Marketing Sales prices are:
Marketing
• Cost plus profit margin $43 - $46 Million
(Bundled gas deliveries & • Cost plus demand charges
(Bundled gas deliveries &
peaking sales)
peaking sales)
Margins: More predictable
Impacted by gas price spread values
in the market (arbitrage opportunity)
Asset Optimization
Asset Optimization $32 - $39 Million
Physical storage capabilities
Available storage and transport
(Storage & transportation
(Storage & transportation capacity
management)
management)
Margins: More variable
=
Total margins reflect:
Stability from marketing margins
$75 - $85 Million
Upside from optimizing our storage
Total AEM
Total AEM and transportation assets to capture
Margins
Margins arbitrage value
Margins: Stable with potential upside
41
42. Consolidated Financial Results – Fiscal 2007E
Capital Expenditures
In the 2006 fiscal year, Atmos Energy spent $425.3
million in capital expenditures
For fiscal 2007, we project between $425-$440 million
in capital expenditures
Approximately $251 - $262 million maintenance
o Nonutility: $42 million - $47 million
o Utility: $209 million - $215 million
Approximately $174 - $178 million growth
o Nonutility: $78 million - $79 million
o Utility: $96 million – $99 million
42
43. Consolidated Financial Results – Fiscal 2007E
Minimizing Volatility With Gas Supply Hedging
For the 2006-2007 heating season, Atmos Energy is hedging
approximately 49 percent of its expected winter gas utility supply
requirements
22 percent are naturally hedged through a combination of owned
underground storage assets and contract pipeline storage
27 percent is hedged through the use of financial derivatives (primarily
futures and fixed forward contracts)
We project the weighted-average cost for storage gas and financial
contracts to be approximately $7.53 per Mcf. This compares to a
weighted-average cost of approximately $9.06 per Mcf for the same
period last year
Hedging provides relative protection to the company and its
customers against volatility in gas prices
Customers will pay a blended rate for gas costs
Atmos Energy should reduce the effects of higher gas prices on its
customer receivables and working capital requirements 43
44. Consolidated Financial Results – Fiscal 2007E
Pension, Post-Retirement & Other Benefits Expense
(in millions)
$59.1
$53.3 Other
$60.0
Medical & Dental
10.4
$50.0 9.3 Post-Retirement
Pension
$40.0
25.3
20.1
$30.0
2007 Pension Assumptions
$20.0 14.2 12.8 8.25% return on plan assets
6.30% discount rate
$10.0 4.00% wage increase
10.6
9.7
$0.0
2006 2007E
44
54. As a Reminder…
The audio and slide presentation of this conference call
will be available on Atmos Energy’s Web site by 8:00 a.m.
Eastern Standard Time on November 8, 2006, through
midnight on February 6, 2007. Atmos Energy’s Web site
address is: www.atmosenergy.com.
To listen to the live conference call, dial 800-257-1836 by
8:00 a.m. Eastern Standard Time on November 8, 2006.
54
56. Atmos Energy Marketing
Economic Value vs. GAAP Reported Results
We commercially manage our storage assets by capturing arbitrage value through
optimization strategies that create embedded (forward) value in the portfolio. We
report the transactions for external reporting purposes in accordance with GAAP.
GAAP Reported Value is the period to period net change in fair value of the
portfolio reported in the income statement that results from the process of marking
to market the physical storage volumes and corresponding financial instruments in
an interim period.
Economic Value is the period to period forward margin of our storage portfolio
that results from the process of calculating our weighted average cost of inventory
(WACOG), and our weighted average sales price of our forward financials
(WASP), then multiplying the difference times inventory volumes. This margin will
be realized in cash when the hedged transaction is settled.
Economic Value represents the “forward” economic margin of the transactions, while GAAP
reported results reflect that portion of our “forward” margin that has been recorded in the income
statement.
Volatility in earnings includes the impact of the accounting treatment of our storage portfolio and is
reflective of relatively high price volatility of the prompt month and the relatively low volatility of the
offsetting forward months.
56
57. Atmos Energy Marketing
Economic Value vs. GAAP Reported Results
Reported GAAP Economic Value*
Reported GAAP
Value (Commercial Value)
Value
- -Physical and Financial
Physical and Financial - Physical and Financial
Positions Positions
Positions
$60.0 MM
($16.0 MM)
($16.0 MM)
Market Spread
Embedded margin
difference
*Realizing Economic Value
$76.0 MM is dependent on ability to
execute – deliver physical
gas & close financial hedges
Supporting data appears on
the following slide
At September 30, 2006 57
58. Atmos Energy Marketing
Economic Value vs. GAAP Reported Results
Physical Economic Value (EV) GAAP Reported Value - MTM Market Spread
($ per Bcf)
Period Volume Total Total Total
WASP WACOG EV ($ in millions) ($ per Bcf) ($ in millions) ($ per Bcf) ($ in millions)
Ending (Bcf)
14.1 7.7606 6.5967 1.1639 (0.5559) 1.7198
6/30/2005 16.4 (7.8) 24.2
6.9 6.3466 4.4435 1.9031 (2.1502) 4.0533
9/30/2005 13.1 (14.8) 27.9
19.0 10.2353 8.7417 1.4936 (3.0297) 4.5233
6/30/2006 28.4 (57.7) 86.1
14.5 11.9716 7.8329 4.1387 (1.1076) 5.2463
9/30/2006 60.0 (16.0) 76.0
(4.5) $ 1.7363 $ (0.9088) $ 2.6451 1.9221 $ 0.7230
Variance $ 31.6 $ 41.7 $ (10.1)
WASP: Weighted average sales price for gas held in storage
WACOG: Weighted average cost of AEM’s gas in storage
EV: “Economic Value” which equals gas sales price (WASP) minus cost of gas (WACOG) on a per unit basis
58
59. Atmos Pipeline and Storage
Straight Creek Gathering
System
Interstate transmission
lines continue on to major
Construction of approximately 60 miles
cities in the Northeast
of gathering facilities in eastern Kentucky
Should relieve severe pipeline
constraints and accommodate rapidly
expanding production in the region (Big
Sandy)
Estimated cost is $75-$80 million
Kinzer Drilling will have an ownership
interest in the project
Received exemption from regulatory
oversight by the Federal Energy
Regulatory Commission but pending other
regulatory approvals
Anticipate construction to begin in first
half of fiscal 2007 with operations
beginning in fiscal 2008
59
61. Atmos Pipeline - Texas
Project Update
CAPEX* GRIP Filings **
Project 2005 2006 2005 2006
Northside Loop
JV with Energy $1.6 million $54.6 million $15.2 million $41.0 million
Transfer
Enbridge
---
Line/Corridor $4.0 million $16.1 million $20.1 million
Compression
Devon Line/
Corridor ---- ---- ---- ----
Compression
Katy Capacity ----
Expansion/ $1.3 million $13.0 million $14.3 million
Compression
Total: $6.9 million $83.7 million $15.2 million $75.4 million
Estimated total annual revenues are $15.0 million. All projects were placed in-service in June 2006.
* CAPEX is calculated on a fiscal year basis
** Capital expenditures are included in GRIP filings on a calendar year basis and when the asset is operational
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62. Atmos Pipeline - Texas
Project Map
North Side
Loop
Enbridge
Compression
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