RAM Energy
Resources, Inc.
August 15, 2006
Highlights – 2Q 06
•RAM Energy, Inc. completes merger with Tremisis to become
publicly traded RAM Energy Resources, Inc.
•RAM selected for inclusion in Russell 2000 index
•2Q 06 production increased 3% over 1Q 06 level
•Emerging production from Barnett Shale growing in importance,
currently fourth largest producing area
•RAM initiates exploration play, targets Wolfcamp shale in
Southwest Texas
•First half capital spending of $10.5 MM on pace with planned
full-year non-acquisition spending of $24.3 MM.
2
Sequential Quarterly Production
Oil & NGL (1) (3)
(thousand Bbl)
Gas (1)
(MCF)
234
2Q06
600
329
318
218
566
1Q06
2Q06
Up 7%
(1)
BOE
(thousands)
1Q06
Down 6%
(1) As reported,
(2) A “reversionary interest” which became effective in September 2005 impacts 1H06 vs 1H05
production comparisons.
(3) Oil & NGL production in 2Q06 is composed of 202M bbl oil and 32M bbl of NGLs. In 1Q06
the composition is 187M bbl oil and 31M bbl NGLs.
2Q06
1Q06
Up 3%
3
Second Quarter Production
Oil & NGL (1)
(thousand Bbl)
Gas (1)
(MCF)
652
234
232
2Q06 2Q05
Up 1%
566
2Q06 2Q05
Down 13%
BOE
(thousands)
As Reported
340
(1)
(1)
329
2Q06 2Q05
Down 3%
BOE
(thousands)
Excluding
Reversionary Impact
(2)
346
340
(1)
2Q06 2Q05
Up 2%
(1) As reported,
(2) Represents total BOE production as if “reversionary interest” which became effective in September 2005
had not been in effect during 2Q06.
4
Realized Prices
(2Q06 VS 2Q05)
Oil
(Per Bbl)
$67.35
$50.95
NGL
(Per Bbl)
Gas
(Per Mcf)
$6.36
$38.21
$36.49
2Q06 2Q05
2Q06 2Q05
Up 32%
Up 5%
$5.54
2Q06 2Q05
Down 13%
BOE
$54.70
$45.08
2Q06 2Q05
Up 21%
5
Second Quarter Results
($ In Millions)
Net Income
Excluding Certain
Non-Cash Items
Net Income (Loss)
As Reported
Non-GAAP (1)
Cash Flow From
Operations
$4.0
$0.3 (2)
$-3.1
(1)
$3.6
(1)
$-0.3
2Q06
2Q06
2Q05
2Q06
2Q05
(1) As reported
(2) Net income in 2Q06 exclusive of certain non–cash charges associated with the merger and unrealized derivative losses.
(3) Cash flow is a non-GAAP measure. See appendix for a reconciliation of this non-GAAP measure to thecorresponding
GAAP amount.
6
Drilling Success Rate
1st Half 06
Total Wells Drilled
1987-YTD 2006 (1)
Producers
Dry Holes
Drilling or Completing
43
2
1
472
38
1
Total
46
511
Success Ratio
(1) Gross wells drilled
(2) Excluding wells in progress
(2)
96%
93%
7
Areas of Operations
Tulsa Office
Houston-District Office
Electra-Field Office
1
2
4
A
B
3
5
Exploration Projects
A
Barnett & Woodford Shale Reeves County, TX
B
Wolfcamp Shale Southwest TX
Principal Fields
1 Electra/Burkburnett
2 Boonsville
3 Egan
4 Barnett Shale
5 Vinegarone
8
Electra/Burkburnett Area, Wichita and
Wilbarger Counties,Texas
•
•
•
•
2Q06 production of 174,328 BOE
from 495 producers
41 Wells drilled in 1st half 06, all of
which completed as producers
167 identified PUD drilling
locations(1)
100% WI ownership & operational
control
•
•
•
Gas plant and gathering
system
Proved reserves of 9,802
MBOE(2)
PV-10% = $182.9 million(2)
(1) At 6/30/06
(2) At year-end 2005
9
Boonsville Area, Jack and Wise Counties, Texas
•
•
•
•
•
•
•
2Q06 production of over
46,650 BOE from 86
producers
21 identified drilling
locations and numerous
low-cost workovers
Operating control of 85
producing wells
Producing wells hold
Barnett Shale rights
25 miles of gas gathering
system
Proved reserves of 3,011
MBOE(1)
PV-10% = $43.4 million(1)
(1) At year-end 2005
10
Egan Field, Acadia Parish, Louisiana
•
•
•
•
•
2Q06 production of 21,476
BOE from 10 producers
Multizone recompletion
potential in 7 existing
wellbores
Operating and ownership
control of field
Proved reserves of 1,652
MBOE(1)
PV-10% = $38.7 million(1)
(1) At year-end 2005
11
Barnett Shale - Jack and
Wise Counties, Texas
Jack Co.
Wise Co.
•
•
•
•
•
EOG (1)
RAM (2)
Devon (6)
Operated wells
•
2Q06 8 wells produced 18,037 BOE
Own WI ranging from 23-36% in the
27,700 gross acres lying within a 43
square mile area
All acreage is HBP leasehold
300 plus potential horizontal
drilling locations
35.28 square miles of 3D seismic
Over 80% of the acreage lies in
“core” area*
*Per Pickering Energy Partners, Inc. October 2005 titled “The
Barnett Shale, Visitors Guide to the Hottest Gas Play in the
US”
12
Vinegarone Field, Val Verde County, Texas
•
•
•
•
•
•
2Q06 production of 13,524 BOE
from 7 non-operated producers
3 PUDs to spud in 3Q06
4 PUDs remaining for future
development
Long-lived natural gas field
Proved reserves of 1,111 MBOE(1)
PV-10% = $21.5 million(1)
(1) At year-end 2005
13
Exploration Projects
• Barnett and Woodford Shale - Reeves County,
Texas
• Wolfcamp Shale – Southwest Texas
14
Summary Financial and Operating Data
3 Year
CAGR(1) 1st Half 06
2003
2004
2005
671
511
1,405
41%
647
Revenue
(millions)
$20.1
$18.0
$66.2
85%
$34.8
EBITDA
(millions)
$9.1
$5.1
$33.7
59%
$17.1
Production
(MBOE)
(1) CAGR is compound annual growth rate for the three year period ended 12/31/05
(2) First half 2006 production as reported, includes the effect of vesting of reversionary interest which occurred
in late 2005. The reversionary interest had the effect of reducing 1H06 production by approximately 40,000 BOE.
15
Financial Flexibility
June 30, 2006
• Liquidity Analysis
($ millions)
Cash ($MM)
Availability under revolving
facility ($MM)
Liquidity ($MM)
$12.9
37.0
49.9
• Long-term Debt
11.5% Sr. Note (1)
Sr. Secured Credit Facility
Installment Loan
Total
$28.3
(2)
103.0
0.5
131.8
(1) Due 2008
(2) Recent $300 million Sr. Secured Credit Facility with initial borrowing limit of $140 million
provides expanded financial flexibility for growth
16
Attractive Valuation vs. Peers
TEV/Reserves ($/BOE)
TEV/PV-10 (3)
Reserve Life Index (in Years)
% Proved Developed
Net Asset Value per Share
Price/NAV
(4)
(1)
RAM
Peers
$15.50
.8x
13.4
70.0
$24.8
5 1.3x
13.7
55.0
$7.02
0.77x
Cash Flow Multiple
(2)
1.39x
7.9x
(1) Share prices as of July 31, 2006
(2) Peers include ABP, BEXP, CRZO, CRK, CWEI, EPEX, GDP, PLLL
(3) PV-10 is based on YE 2005 proved reserves and prices as reported by RAM and Peers
(4) RAM NAV is based on PV-10% of proved reserves and pricing at December 31, 2005 and does
not include unproved reserves or oil and gas gathering and processing assets; also does
not include exercise of outstanding warrants
17
Disclosure Statement
This document contains forward-looking statements within the meaning of Section 27A
of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of
1934, as amended. All statements, other than statements of historical fact, including, without
limitation, statements that address estimates of RAM’s proved reserves of oil, gas and
natural gas liquids, its derivative positions, the impact of derivatives, exploration activities,
capital spending, borrowing availability, financial position, business strategy, and RAM’s
management’s objectives and its future operations, and industry conditions, are forwardlooking statements. Although RAM believes that the expectations reflected in such forwardlooking statements are reasonable, RAM can give no assurance that such expectations will
prove to be correct. Important factors that could cause actual results to differ materially from
RAM’s expectations (“Cautionary Statements”) include, without limitation, the actual
quantities of RAM’s oil and natural gas reserves, future production levels, future prices and
demand for oil and natural gas, the results of RAM’s future exploration and development
activities, future operating, development costs and future acquisitions, the effect of existing
and future laws and governmental regulations (including those pertaining to the
environment), the continued availability of capital and financing, and the political and
economic climate of the United States as well as risk factors listed from time to time in our
reports and documents filed with the SEC. All subsequent written and oral forward-looking
statements attributable to RAM, or persons acting on RAM’s behalf, are expressly qualified in
their entirety by the Cautionary Statements.
18
APPENDIX
19
Production Volumes and
Expenses
Quarter Ended June
2005
2006
Increase
(Decrease)
(in thousands, except per unit amounts)
Production volumes:
Oil and condensate (MBbls)
Natural gas liquids (MBbls)
Natural gas (MMcf)
Total (Mboe)
190
42
652
340
Expenses (per Boe):
Oil and natural gas production taxes
$2.28
Oil and natural gas production expenses $11.28
Amortization of full-cost pool
$8.00
General and administrative
$5.46
Share - based compensation
$ -
202
32
566
329
$2.66
$14.02
$9.60
$6.35
$6.75
6.4%
-23.2%
-13.1%
-3.5%
16.5%
24.3%
20.0%
16.3%
100.0%
20
Production Volumes and
Expenses
Six Months Ended June 30
2005
2006
Increase
(Decrease)
(in thousands, except per unit amounts)
Production volumes:
Oil and condensate (MBbls)
Natural gas liquids (MBbls)
Natural gas (MMcf)
Total (Mboe)
396
91
1,236
692
Expenses (per Boe):
Oil and natural gas production taxes
$2.23
Oil and natural gas production expenses $10.89
Amortization of full-cost pool
$8.31
General and administrative
$5.66
Share - based compensation
$ -
389
63
1,167
647
$2.60
$13.78
$9.55
$6.26
$3.43
-1.70%
-30.30%
-5.60%
-6.60%
16.60%
26.50%
14.90%
10.60%
100.00%
21
Derivative Positions
Crude Oil (Bbls)
Year
2006
2007
2008
Floors
per day
Price
1,500
$43.33
1,500
$52.67
1,000
$53.34
Bare Floors
2006
250
2006
2007
Ceilings
per day
Price
1,500
$65.80
1,500
$73.24
1,000
$86.37
Natural Gas (Mmbtu)
Floors
Ceilings
per day
Price
per day
Price
5,000
$6.33
5,000
$9.31
4,247
$7.43
4,247
$11.62
4,000
$7.16
4,000
$13.25
$40.00
Secondary Floors
-
Secondary Floors
5,000
$9.50
4,000
$12.00
Natural gas secondary floors for 2006 are for July through October and 2007 are for April through October.
Natural gas floors/ceilings and oil floors/ceilings for 2008 are for January through September.
As of June 30, 2006
22
Non-GAAP
Financial Measure
Cash flow, a non-GAAP measure, represents cash provided by operating activities
before the impact of discontinued operations, changes in working capital items related
to operating activities, and further adjusted for unrealized gains or losses on derivative
transactions This non-GAAP measure is presented because management believes it is
a useful adjunct to cash provided by operating activities under accounting principles
generally accepted in the United States (GAAP). This non-GAAP cash flow measure is
widely accepted as a financial indicator of an oil and gas company’s ability to generate
cash which is used to internally fund exploration and development activities and to
service debt. This non-GAAP measure is not a measure of financial performance under
GAAP and should not be considered as an alternative to cash provided (used) by
operating, investing, or financing activities as an indicator of cash flows, or as a
measure of liquidity.
23
Cash Flow
Reconciliation of cash flow from operations (a non-GAAP measure)
to GAAP cash flow from operating activities
June 30
2006
(in thousands)
June 30
2005
(in thousands)
Cash flow from operations (a non-GAAP measure)
Plus: working capital changes
Less: deferred income taxes on share-based compensation
classified as financing activities
Net cash provided by operating activities per condensed
consolidated statements of cash flow
$3,983
3,454
$3,579
3,146
(843)
-
$8,280
$6,725
Cash flow from operations (a non-GAAP measure)
Less: realized (losses) on derivatives
Less: unrealized gains (losses) on derivatives per condensed
consolidated statements of cash flow
Cash flow from operations (a non-GAAP measure) excluding
realized and unrealized gains (losses) on derivatives
$3,983
(2,043)
$3,579
(468)
(2,135)
(3,326)
$8,161
$7,373
24