Delaware
(State
or other jurisdiction
of
incorporation or organization)
|
41-0518430
(I.R.S.
Employer Identification No.)
|
1776
Lincoln Street, Suite 700, Denver, Colorado
(Address
of principal executive offices)
|
80203
(Zip
Code)
|
Title
of each class
|
Name
of each exchange on which registered
|
|
Common
stock, $.01 par value
|
New
York Stock Exchange
|
Large
accelerated filer þ
|
Accelerated
filer o
|
Non-accelerated
filer o (Do
not check if a smaller reporting company)
|
Smaller
reporting company o
|
TABLE OF CONTENTS
|
||
ITEM
|
PAGE
|
|
PART
I
|
||
ITEMS
1. and 2.
|
BUSINESS
and
PROPERTIES
|
1
|
General
|
1
|
|
Strategy
|
1
|
|
Significant Developments in
2008
|
1
|
|
Outlook for
2009
|
4
|
|
Assets
|
4
|
|
Reserves
|
8
|
|
Production
|
10
|
|
Productive
Wells
|
10
|
|
Drilling
Activity
|
11
|
|
Acreage
|
12
|
|
Major
Customers
|
12
|
|
Employees and Office
Space
|
12
|
|
Title to
Properties
|
13
|
|
Seasonality
|
13
|
|
Competition
|
13
|
|
Government
Regulations
|
13
|
|
Cautionary Information about
Forward-Looking Statements
|
15
|
|
Available
Information
|
16
|
|
Glossary of Oil and Natural Gas
Terms
|
17
|
|
|
||
ITEM
1A.
|
RISK
FACTORS
|
21
|
|
||
ITEM
1B.
|
UNRESOLVED
STAFF
COMMENTS
|
31
|
ITEM
3.
|
LEGAL
PROCEEDINGS
|
31
|
ITEM
4.
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY
HOLDERS
|
31
|
ITEM
4A.
|
EXECUTIVE
OFFICERS OF THE
REGISTRANT
|
32
|
PART
II
|
||
ITEM
5.
|
MARKET
FOR REGISTRANT’S COMMON EQUITY,
RELATED
STOCKHOLDER MATTERS AND ISSUER
PURCHASES
OF EQUITY
SECURITIES
|
35
|
ITEM
6.
|
SELECTED
FINANCIAL
DATA
|
38
|
ITEM
7.
|
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
|
40
|
Overview of the
Company
|
40
|
|
Overview of Liquidity and
Capital
Resources
|
51
|
|
Critical Accounting Policies
and
Estimates
|
62
|
|
Additional Comparative Data in
Tabular
Format
|
65
|
|
Comparison of Financial Results
and Trends between
2008 and
2007
|
66
|
|
Comparison of Financial Results
and Trends between
2007 and
2006
|
69
|
|
Other Liquidity and Capital
Resources Information
|
72
|
|
Accounting
Matters
|
72
|
|
Environmental
|
72
|
TABLE OF CONTENTS
|
||
(Continued)
|
||
ITEM
|
PAGE
|
|
ITEM
7A.
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT
MARKET
RISK (included with the content of ITEM 7)
|
73
|
ITEM
8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
|
73
|
ITEM
9.
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON
ACCOUNTING AND FINANCIAL DISCLOSURE
|
73
|
ITEM
9A.
|
CONTROLS
AND
PROCEDURES
|
73
|
ITEM
9B.
|
OTHER
INFORMATION
|
76
|
PART
III
|
||
ITEM
10.
|
DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
|
76
|
ITEM
11.
|
EXECUTIVE
COMPENSATION
|
76
|
ITEM
12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS
AND MANAGEMENT AND RELATED
STOCKHOLDER
MATTERS
|
76
|
ITEM
13.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS,
AND
DIRECTOR
INDEPENDENCE
|
76
|
ITEM
14.
|
PRINCIPAL
ACCOUNTANT FEES AND SERVICES
|
77
|
PART
IV
|
||
ITEM
15.
|
EXHIBITS
AND FINANCIAL STATEMENT SCHEDULES
|
77
|
·
|
Acquire
significant leasehold positions in new and emerging resource
plays
|
·
|
Leverage
our core competencies in drilling and completions, as well as
acquisitions
|
·
|
Exploit
our significant legacy asset production and optimize our asset base
through divestitures of non-core assets when
appropriate
|
·
|
Maintain
a strong balance sheet while funding the growth of the
enterprise.
|
·
|
Broad Economic Downturn and
Impacts on Capital Markets and Commodity Prices. During
2008 the global economy experienced a significant downturn. The
crisis began over concerns related to the U.S. financial system and
quickly grew to impact a wide range of industries. There were
two significant ramifications to the exploration and production industry
as the economy continued to deteriorate. The first was that
capital markets essentially froze. Equity, debt, and credit
markets shut down. We were able to weather this initial shock
as a result of our strong liquidity position and relatively limited
capital commitments. The second impact to the industry was that
fear of global recession resulted in a significant decline in oil and gas
prices. We have been able to cope with the downturn in prices
as a result of our ability to quickly scale down our activity and keep our
capital investments within cash flow. Our existing commodity
hedge position provided a further backstop as commodity prices continued
to decline. We believe the environment in 2009 will continue to
be challenging with respect to financing and commodity
pricing.
|
·
|
Significant Volatility in
Commodity Prices. As mentioned above, 2008 saw the
exploration and production sector impacted by significant volatility in
the prices for crude oil and natural gas. Our operations and
financial condition are significantly impacted by these
prices. Our crude oil is sold on contracts that pay us the
average of posted prices for the period in which the crude oil is
sold. The spot price for NYMEX crude oil in 2008 ranged from a
high of $145.29 per barrel in early July to a low of $31.41 per barrel in
late December. The average spot price for oil during the year
was $99.92 per barrel. The volatility in oil prices during the
year was a result of geopolitical unrest in various producing regions
overseas as well as domestic
concerns about refinery utilization and petroleum product inventories
pushing prices up during the first half of the year. Global
demand destruction drove prices down as the economy weakened in the second
half of 2008.
|
|
We sell the majority of our natural gas on contracts that are based
on first of the month (also frequently referred to as bid week) index
pricing. The Inside FERC bid week price for Henry Hub, a widely used
industry measuring point, averaged $9.04 per MMBtu in 2008, with a high of
$13.11 per MMBtu in July and a low of $6.47 per MMBtu in
November. Natural gas prices came under pressure in the second
half of the year as a result of lower domestic product demand that was
caused by the weakening economy and concerns over excess supply of natural
gas due to high levels of drilling activity. Some of the
regional markets where we sell gas have seen increased downward pressures
on price as a result of high levels of activity in the region and either a
lack of pipeline takeaway capacity or local demand. This has
been most pronounced in our Mid-Continent and Rocky Mountain
regions.
|
·
|
Decrease in Year-End
Reserves. Due in large part to the price declines in the
second half of 2008 described above, proved reserves decreased 20 percent
to 865.5 BCFE at December 31, 2008, from 1,086.5 BCFE at
December 31, 2007. We added 170.1 BCFE from our drilling
program and 29.1 BCFE from acquisitions during the year. During
the year, 61.4 BCFE were sold in divestitures, primarily in the Rocky
Mountain and Mid-Continent regions. We had a negative revision
of 244.2 BCFE that consisted of 44.5 BCFE in downward performance
revisions and a downward pricing revision of 199.7 BCFE due primarily to
meaningfully lower commodity prices at the end of 2008. The
prices used for the 2008 year-end reserves decreased significantly from a
year earlier. Oil prices declined 54 percent from $95.98 per
barrel to $44.60 per barrel while natural gas prices dropped 16 percent
from $6.80 per MMBtu to $5.71 per MMBtu. Over half of the
pricing revisions occurred in the oil-weighted Rocky Mountain region,
which saw its proved reserves adversely impacted by low prices and wider
differentials at the end of 2008. We also saw meaningful price
and performance revisions in the Gulf Coast region related primarily to
our Olmos shallow gas properties in South Texas. A large
decline in the natural gas liquid fractionation spread year over year
resulted in a significantly lower price for natural gas in the
determination of proved reserves for the region at
year-end. The performance revision is due to poorer reservoir
performance then we initially expected. The reservoir is more
compartmentalized then originally assumed and we have seen lower reserve
outcomes while attempting to infill parts of the
field.
|
·
|
Impairment of Proved
Properties. The low prices at year-end for oil and gas
and the decrease in proved reserves described above both contributed to a
pre-tax non-cash impairment of proved properties in the amount of $302.2
million in 2008. There was no impairment of proved properties
in 2007. Approximately $154.0 million of the 2008 impairment
was related to assets in South Texas that were acquired in
2007. We also saw an impairment associated with proved
properties in the Gulf of Mexico, the Greater Green River Basin in
Wyoming, and our coalbed methane project at Hanging Woman
Basin.
|
·
|
Abandonment and Impairment of
Unproved Properties. During the year, we abandoned or
impaired $39.0 million related to unproved
properties. Approximately $13.4 million was related to acreage
to which we had assigned value in 2007 acquisitions targeting the Olmos
shallow gas. The remaining write-offs were related to acreage
we believe we will not be able to hold due to current limited capital
availability and to acreage that we do not believe is
prospective.
|
·
|
Drilling
Results. Reserve additions of 170.1 BCFE from drilling
activities were driven primarily by results in the Mid-Continent and
Permian Basin regions, with those regions contributing 43 percent and 22
percent, respectively, to our drilling additions. The ArkLaTex
and Rocky Mountain regions contributed 14 percent and 15 percent,
respectively, to our drilling additions. The Mid-Continent
region had a very strong year. Additions in the Mid-Continent
region were derived principally by successful drilling by us and our
operating partners in the horizontal Woodford shale formation in the
Arkoma Basin, as well as positive results from a program targeting the
deep Springer interval in the Anadarko Basin. In the Permian
region, additions were the result of successful drilling in our Wolfberry
tight oil program. The ArkLaTex region added reserves from
successful Cotton Valley formation development drilling by us at Carthage
Field and by an operating partner at Elm Grove Field. Coalbed
methane projects at Atlantic Rim and in Hanging Woman Basin accounted for
the majority of drilling additions in the Rocky Mountain
Region.
|
·
|
Potential Resource Play
Additions. In 2008 we established meaningful positions
in several new potential resource plays which emerged in the exploration
and development industry, principally the Haynesville shale, the Eagle
Ford shale, and the Marcellus shale. Although no proved
reserves have been booked in any of these emerging resource plays at the
end of 2008, each of these plays could provide for significant future
growth in reserves and production if development proves
successful. The Haynesville shale emerged early in 2008 in
North Louisiana and East Texas and quickly became the hottest resource
play in the country. As a result of our previous Cotton Valley
and James Lime activity and the acquisition of additional properties in
Panola County, Texas in early 2008, we now have approximately 50,000 net
acres that could be prospective for the Haynesville shale. Our
Eagle Ford shale position in the Maverick Basin in South Texas was seeded
through two acquisitions in 2007 and then built through leasing efforts
and a joint venture over the course of 2008. If we earn all of
the acreage available under the joint venture, St. Mary will control
approximately 210,000 net acres in this play. Lastly, late in
2008 we entered into two arrangements that allow us to earn up to 43,000
net acres in the Marcellus shale in north central
Pennsylvania.
|
·
|
Divestiture of Non-Strategic
Properties. In 2008 we sold a number of non-strategic
properties in an effort to optimize our portfolio. Prior to
this year we had been a limited seller of assets. The primary
objectives of these sales were to dispose of properties with limited
upside drilling potential and to focus our employees on the core strategic
assets that will help the Company grow in the future. During
2008 we sold 61.4 BCFE of reserves, the vast majority of which were proved
producing. The sales occurred throughout the year and we
received $178.9 million in proceeds from these sales. The
properties we sold were located primarily in the Rocky Mountain and
Mid-Continent regions.
|
·
|
Senior Management
Change. On March 21, 2008, David Honeyfield, Senior Vice
President - Chief Financial Officer and Secretary, resigned as an officer
of St. Mary, to pursue an opportunity in an unrelated
industry. On September 8, 2008, A. Wade Pursell joined St. Mary
as Executive Vice President and Chief Financial Officer. Mr.
Pursell was employed at Helix Energy Solutions as Chief Financial Officer
from 2000 until mid-2008 and as Vice President – Finance and Treasurer
from 1997 through 2000. Prior to that, he spent nine years in
the audit practice of Arthur Andersen in positions of increasing
responsibility.
|
·
|
Repurchase of Common
Stock. During the first quarter of 2008, we repurchased
a total of 2,135,600 shares of common stock in the open market for a
weighted-average price of $36.13 per share, including
commissions. At the time we repurchased our shares, we entered
into hedges for a commensurate amount of our production that was
represented by the share repurchase in order to lock in the discounted
price at which we believed our shares were trading. As of the
date of this filing, we are authorized by the Board to repurchase
3,072,184 additional shares under our share repurchase
program. The shares may be repurchased from time to time in
open market transactions or in privately negotiated transactions, subject
to market conditions and other factors, including certain provisions of
our existing credit facility agreement and compliance with securities
laws. Stock repurchases may be funded with existing cash
balances, internal cash flow, and/or borrowings
under
|
|
the
credit facility. Given current economic conditions, we do not
currently anticipate that in the near term we will be utilizing our
liquidity and capital resources for capital investment to conduct stock
repurchases.
|
ArkLaTex
|
Mid-
Continent
|
Gulf
Coast
|
Permian
|
Rocky
Mountain
|
Total
(1)
|
|||||||
2008
Proved Reserves
|
||||||||||||
Oil
(MMBbl)
|
0.5 | 1.1 | 0.7 | 19.8 | 29.2 | 51.4 | ||||||
Gas
(Bcf)
|
167.1 | 227.8 | 39.4 | 37.1 | 86.0 | 557.4 | ||||||
Equivalents
(BCFE)
|
170.0 | 234.5 | 43.8 | 155.9 | 261.4 | 865.5 | ||||||
Relative
percentage
|
20% | 27% | 5% | 18% | 30% | 100% | ||||||
Proved
Developed %
|
67% | 79% | 92% | 79% | 97% | 83% | ||||||
PV-10
Value (in millions)
|
$ 221.4 | $ 379.2 | $ 47.9 | $ 284.6 | $ 332.2 | $ 1,265.4 | ||||||
Relative
percentage
|
18% | 30% | 4% | 22% | 26% | 100% | ||||||
2008
Production
|
||||||||||||
Oil
(MMBbl)
|
0.2 | 0.4 | 0.2 | 1.8 | 4.1 | 6.6 | ||||||
Gas
(Bcf)
|
17.6 | 30.8 | 12.9 | 3.3 | 10.3 | 74.9 | ||||||
Equivalent
(BCFE)
|
18.6 | 33.0 | 14.3 | 13.8 | 34.9 | 114.6 | ||||||
Avg.
Daily Equivalents
(MMCFE/d)
|
50.7 | 90.2 | 39.0 | 37.8 | 95.4 | 313.1 | ||||||
Relative
percentage
|
16% | 29% | 12% | 12% | 31% | 100% | ||||||
As
of December 31,
|
|||||||||
Proved
Reserves Data:
|
2008
|
2007
|
2006
|
||||||
Oil
(MMBbl)
|
51.4 | 78.8 | 74.2 | ||||||
Gas
(Bcf)
|
557.4 | 613.5 | 482.5 | ||||||
BCFE
|
865.5 | 1,086.5 | 927.6 | ||||||
Standardized
measure of discounted future cash flows (in thousands)
|
$ | 1,059,069 | $ | 2,706,914 | $ | 1,576,437 | |||
PV-10
value (in thousands)
|
$ | 1,265,385 | $ | 3,861,187 | $ | 2,157,449 | |||
Proved
developed reserves
|
83% | 77% | 78% | ||||||
Reserve
replacement – drilling and acquisitions, excluding performance and
price revisions
|
174% | 211% | 232% | ||||||
All
in – including sales of reserves
|
(93)% | 248% | 244% | ||||||
All
in – excluding sales of reserves
|
(39)% | 249% | 247% | ||||||
Reserve
life (years) (1)
|
7.6 | 10.1 | 10.0 | ||||||
(1)
|
Reserve
life represents the estimated proved reserves at the dates indicated
divided by actual production for the preceding 12-month
period.
|
As
of December 31,
|
|||||||||
2008
|
2007
|
2006
|
|||||||
(In
thousands)
|
|||||||||
Standardized
measure of discounted future net cash flows
|
$ | 1,059,069 | $ | 2,706,914 | $ | 1,576,437 | |||
Add:
10 percent annual discount, net of income taxes
|
724,840 | 2,321,983 | 1,238,308 | ||||||
Add:
future income taxes
|
419,544 | 2,316,637 | 1,125,955 | ||||||
Undiscounted
future net cash flows
|
$ | 2,203,453 | $ | 7,345,534 | $ | 3,940,700 | |||
Less:
10 percent annual discount without tax effect
|
(938,068 | ) | (3,484,347 | ) | (1,783,251 | ) | |||
PV-10
value
|
$ | 1,265,385 | $ | 3,861,187 | $ | 2,157,449 |
Years
Ended December 31,
|
|||||||||
2008
|
2007
|
2006
|
|||||||
Net
production
|
|||||||||
Oil
(MMBbl)
|
6.6 | 6.9 | 6.1 | ||||||
Gas
(Bcf)
|
74.9 | 66.1 | 56.4 | ||||||
BCFE
|
114.6 | 107.5 | 92.8 | ||||||
Average
net daily production
|
|||||||||
Oil
(MBbl)
|
18.1 | 18.9 | 16.6 | ||||||
Gas
(MMcf)
|
204.7 | 181.0 | 154.7 | ||||||
MMCFE
|
313.1 | 294.5 | 254.2 | ||||||
Average
realized sales price, excluding the effects of hedging
|
|||||||||
Oil
(per Bbl)
|
$ | 92.99 | $ | 67.56 | $ | 59.33 | |||
Gas
(per Mcf)
|
$ | 8.60 | $ | 6.74 | $ | 6.58 | |||
Per
MCFE
|
$ | 10.99 | $ | 8.48 | $ | 7.88 | |||
Average
realized sales price, including the effects of hedging
|
|||||||||
Oil
(per Bbl)
|
$ | 75.59 | $ | 62.60 | $ | 56.60 | |||
Gas
(per Mcf)
|
$ | 8.79 | $ | 7.63 | $ | 7.37 | |||
Per
MCFE
|
$ | 10.11 | $ | 8.71 | $ | 8.18 | |||
Production
costs per MCFE
|
|||||||||
Lease
operating expense
|
$ | 1.46 | $ | 1.31 | $ | 1.25 | |||
Transportation
expense
|
$ | 0.19 | $ | 0.14 | $ | 0.12 | |||
Production
taxes
|
$ | 0.71 | $ | 0.58 | $ | 0.54 |
Years
Ended December 31,
|
||||||||||||
2008
|
2007
|
2006
|
||||||||||
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||
Development:
|
||||||||||||
Oil
|
221 | 81.46 | 164 | 77.91 | 81 | 35.32 | ||||||
Gas
|
559 | 205.18 | 518 | 204.62 | 446 | 178.97 | ||||||
Non-productive
|
25 | 13.70 | 30 | 13.18 | 31 | 10.65 | ||||||
805 | 300.34 | 712 | 295.71 | 558 | 224.94 | |||||||
Exploratory:
|
||||||||||||
Oil
|
2 | 0.40 | 3 | 1.92 | 10 | 5.53 | ||||||
Gas
|
10 | 2.75 | 9 | 4.01 | 15 | 3.68 | ||||||
Non-productive
|
1 | 0.76 | 5 | 2.58 | 8 | 1.81 | ||||||
13 | 3.91 | 17 | 8.51 | 33 | 11.02 | |||||||
Farmout
or non-consent
|
7 | - | 1 | - | 2 | - | ||||||
Total
(1)
|
825 | 304.25 | 730 | 304.22 | 593 | 235.96 | ||||||
(1)
|
Does
not include three gross wells completed on St. Mary’s fee lands during
2006, in which we have only a royalty
interest.
|
Developed
Acres (1)
|
Undeveloped
Acres (2)
|
Total
|
||||||||||
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||
Arkansas
|
1,434 | 182 | 147 | 60 | 1,581 | 242 | ||||||
Colorado
|
1,646 | 1,455 | 6,663 | 5,225 | 8,309 | 6,680 | ||||||
Kansas
|
- | - | 2,240 | 560 | 2,240 | 560 | ||||||
Louisiana
|
121,688 | 44,831 | 39,146 | 7,462 | 160,834 | 52,293 | ||||||
Mississippi
|
4,329 | 1,069 | 103,609 | 41,843 | 107,938 | 42,912 | ||||||
Montana
|
59,535 | 39,985 | 430,981 | 287,836 | 490,516 | 327,821 | ||||||
Nevada
|
- | - | 243,147 | 243,147 | 243,147 | 243,147 | ||||||
New
Mexico
|
5,026 | 2,561 | 3,033 | 2,343 | 8,059 | 4,904 | ||||||
North
Dakota
|
125,104 | 86,104 | 219,674 | 126,153 | 344,778 | 212,257 | ||||||
Oklahoma
|
250,915 | 78,571 | 110,121 | 53,864 | 361,036 | 132,435 | ||||||
Texas
|
233,201 | 112,387 | 490,081 | 230,856 | 723,282 | 343,243 | ||||||
Utah
|
- | - | 3,328 | 591 | 3,328 | 591 | ||||||
Wyoming
|
127,443 | 87,223 | 397,361 | 228,070 | 524,804 | 315,293 | ||||||
930,321 | 454,368 | 2,049,531 | 1,228,010 | 2,979,852 | 1,682,378 | |||||||
Louisiana
Fee Properties
|
10,499 | 10,499 | 14,415 | 14,415 | 24,914 | 24,914 | ||||||
Louisiana
Mineral Servitudes
|
7,653 | 4,404 | 4,622 | 4,260 | 12,275 | 8,664 | ||||||
18,152 | 14,903 | 19,037 | 18,675 | 37,189 | 33,578 | |||||||
Total
|
948,473 | 469,271 | 2,068,568 | 1,246,685 | 3,017,041 | 1,715,956 | ||||||
(1)
|
Developed
acreage is acreage assigned to producing wells for the spacing unit of the
producing formation. Developed acreage of St. Mary’s properties
that include multiple formations with different well spacing requirements
may be considered undeveloped for certain formations, but have only been
included as developed acreage in the presentation
above.
|
(2)
|
Undeveloped
acreage is lease acreage on which wells have not been drilled or completed
to a point that would permit the production of commercial quantities of
oil and gas, regardless of whether such acreage contains estimated
reserves.
|
·
|
The
amount and nature of future capital expenditures and the availability of
liquidity and capital resources to fund capital
expenditures
|
·
|
The
drilling of wells and other exploration and development activities and
plans, as well as possible future
acquisitions
|
·
|
Reserve
estimates and the estimates of both future net revenues and the present
value of future net revenues that are included in their
calculation
|
·
|
Future
oil and natural gas production
estimates
|
·
|
Our
outlook on future oil and natural gas prices and service
costs
|
·
|
Cash
flows, anticipated liquidity, and the future repayment of
debt
|
·
|
Business
strategies and other plans and objectives for future operations, including
plans for expansion and growth of operations or to defer capital
investment, and our outlook on our future financial condition or results
of operations
|
·
|
Other
similar matters such as those discussed in the “Management’s Discussion
and Analysis of Financial Condition and Results of Operations” section in
Item 7 of this Form 10-K.
|
·
|
The
volatility and level of realized oil and natural gas
prices
|
·
|
A
contraction in demand for oil and natural gas as a result of adverse
general economic conditions
|
·
|
The
availability of economically attractive exploration, development, and
property acquisition opportunities and any necessary financing, including
constraints on the availability of opportunities and financing due to
currently distressed capital and credit market
conditions
|
·
|
Our
ability to replace reserves and sustain
production
|
·
|
Unexpected
drilling conditions and results
|
·
|
Unsuccessful
exploration and development
drilling
|
·
|
The
risks of hedging strategies
|
·
|
The
uncertain nature of the expected benefits from acquisitions and
divestitures of oil and natural gas properties, including uncertainties in
evaluating oil and natural gas reserves of acquired properties and
associated potential liabilities
|
·
|
The
imprecise nature of oil and natural gas reserve
estimates
|
·
|
Uncertainties
inherent in projecting future rates of production from drilling activities
and acquisitions
|
·
|
Declines
in the values of our oil and natural gas properties resulting in
write-downs
|
·
|
The
ability of purchasers of production to pay for amounts
purchased
|
·
|
Drilling
and operating service availability
|
·
|
Uncertainties
in cash flow
|
·
|
The
financial strength of hedge contract counterparties and credit facility
participants, and the risk that one or more of those parties may not
satisfy their contractual
commitments
|
·
|
The
negative impact that lower oil and natural gas prices could have on our
ability to borrow and fund capital
expenditures
|
·
|
The
potential effects of increased levels of debt
financing
|
·
|
Our
ability to compete effectively against other independent and major oil and
natural gas companies
|
·
|
Litigation,
environmental matters, the potential impact of government regulations, and
the use of management estimates.
|
·
|
Global
and domestic supplies of oil and natural gas, and the productive capacity
of the industry as a whole
|
·
|
The
level of consumer demand for oil and natural
gas
|
·
|
Overall
global and domestic economic
conditions
|
·
|
Weather
conditions
|
·
|
The
availability and capacity of transportation or refining facilities in
regional or localized areas that may affect the realized price for oil or
natural gas
|
·
|
The
price and level of foreign imports of crude oil, refined petroleum
products, and liquefied natural gas
|
·
|
The
price and availability of alternative
fuels
|
·
|
Technological
advances affecting energy
consumption
|
·
|
The
ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production
controls
|
·
|
Political
instability or armed conflict in oil or natural gas producing
regions
|
·
|
Governmental
regulations and taxes.
|
·
|
Amount
and timing of actual production
|
·
|
Supply
and demand for oil and natural gas
|
·
|
Curtailments
or increases in consumption by oil purchasers and natural gas
pipelines
|
·
|
Changes
in government regulations or taxes.
|
·
|
Unexpected
drilling conditions
|
·
|
Title
problems
|
·
|
Pressure
or geologic irregularities in
formations
|
·
|
Equipment
failures or accidents
|
·
|
Hurricanes
or other adverse weather conditions
|
·
|
Compliance
with environmental and other governmental
requirements
|
·
|
Shortages
or delays in the availability of or increases in the cost of drilling rigs
and crews, fracture stimulation crews and equipment, chemicals, and
supplies.
|
·
|
Our
production is less than expected
|
·
|
One
or more counterparties to our hedge contracts default on their contractual
obligations
|
·
|
There
is a widening of price differentials between delivery points for our
production and the delivery point assumed in the hedge
arrangement.
|
·
|
Making
it more difficult for us to obtain additional financing in the future for
our operations and potential acquisitions, working capital requirements,
capital expenditures, debt service, or other general corporate
requirements
|
·
|
Requiring
us to dedicate a substantial portion of our cash flows from operations to
the repayment of our debt and the service of interest costs associated
with our debt, rather than to productive
investments
|
·
|
Limiting
our operating flexibility due to financial and other restrictive
covenants, including restrictions on incurring additional debt, creating
liens on our properties, making acquisitions, and paying
dividends
|
·
|
Placing
us at a competitive disadvantage compared to our competitors that have
less debt
|
·
|
Making
us more vulnerable in the event of adverse economic or industry conditions
or a downturn in our business.
|
·
|
Changes
in oil or natural gas prices
|
·
|
Variations
in quarterly drilling, recompletions, acquisitions, and operating
results
|
·
|
Changes
in financial estimates by securities
analysts
|
·
|
Changes
in market valuations of comparable
companies
|
·
|
Additions
or departures of key personnel
|
·
|
Future
sales of our common stock
|
·
|
Changes
in the national and global economic
outlook.
|
Name
|
Age
|
Position
|
Anthony
J. Best
|
59
|
Chief
Executive Officer and President
|
Javan
D. Ottoson
|
50
|
Executive
Vice President and Chief Operating Officer
|
A.
Wade Pursell
|
43
|
Executive
Vice President and Chief Financial Officer
|
Mark
D. Mueller
|
44
|
Senior
Vice President and Regional Manager
|
Milam
Randolph Pharo
|
56
|
Senior
Vice President and General Counsel
|
Paul
M. Veatch
|
42
|
Senior
Vice President and Regional Manager
|
Stephen
C. Pugh
|
50
|
Senior
Vice President and Regional Manager
|
Gregory
T. Leyendecker
|
51
|
Vice
President – Regional Manager
|
John
R. Monark
|
56
|
Vice
President – Human Resources and Administration
|
Lehman
E. Newton, III
|
53
|
Vice
President – Regional Manager
|
Kenneth
J. Knott
|
44
|
Vice
President – Business Development and Land and Assistant
Secretary
|
David
J. Whitcomb
|
46
|
Vice
President – Marketing
|
Dennis
A. Zubieta
|
42
|
Vice
President – Engineering and Evaluation
|
Mark
T. Solomon
|
40
|
Controller
|
ITEM
5.
|
MARKET
FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
|
Quarter
Ended
|
High
|
Low
|
||||
December
31, 2008
|
$ | 35.81 | $ | 14.76 | ||
September
30, 2008
|
65.58 | 32.53 | ||||
June
30, 2008
|
65.00 | 37.73 | ||||
March
31, 2008
|
39.95 | 31.70 | ||||
December
31, 2007
|
$ | 44.50 | $ | 35.40 | ||
September
30, 2007
|
37.15 | 31.20 | ||||
June
30, 2007
|
40.19 | 34.91 | ||||
March
31, 2007
|
38.20 | 33.55 |
(a)
|
(b)
|
(c)
|
||||||
Plan
category
|
Number
of securities to be issued upon exercise of outstanding options, warrants,
and rights
|
Weighted-average
exercise price of outstanding options, warrants, and
rights
|
Number
of
securities
remaining available for future issuance under
equity
compensation plans (excluding securities reflected in column
(a))
|
|||||
Equity
compensation plans approved by security holders:
|
||||||||
2006
Equity Incentive Compensation Plan
|
||||||||
Stock
options and incentive stock options (1)
|
1,509,710 | $ | 12.69 | - | ||||
Restricted
stock (1)
|
409,388 | - | - | |||||
Performance
share awards (1)
|
464,333 | $ | 26.48 | 1,529,140 | ||||
Total
for 2006 Equity Incentive Compensation Plan
|
2,383,431 | $ | 15.93 | 1,529,140 | ||||
Employee
Stock Purchase Plan (2)
|
- | - | 1,554,583 | |||||
Equity
compensation plans not approved by security holders
|
- | - | - | |||||
Total
for all plans
|
2,383,431 | $ | 15.93 | 3,083,723 | ||||
(1)
|
In
May 2006 the stockholders approved the 2006 Equity Plan to authorize the
issuance of restricted stock, restricted stock units, non-qualified stock
options, incentive stock options, stock appreciation rights, and
stock-based awards to key employees, consultants, and members of the Board
of Directors of St. Mary or any affiliate of St. Mary. The 2006
Equity Plan serves as the successor to the St. Mary Land &
Exploration Company Stock Option Plan, the St. Mary Land & Exploration
Company Incentive Stock Option Plan, the St. Mary Land & Exploration
Company Restricted Stock Plan, and the St. Mary Land & Exploration
Company Non-Employee Director Stock Compensation Plan (collectively
referred to as the “Predecessor Plans”). All grants of equity
are now made out of the 2006 Equity Plan, and no further grants will be
made under the Predecessor Plans. Each outstanding award under
a Predecessor Plan immediately prior to the effective date of the 2006
Equity Plan continues to be governed solely by the terms and conditions of
the instruments evidencing such grants or issuances. In late
2007, St. Mary transitioned to PSA grants as the primary form of long-term
equity incentive compensation for eligible employees in place of grants of
RSUs. The Company’s Board of Directors approved an amendment
and restatement of the 2006 Equity Incentive Compensation Plan on March
28, 2008, and the amended plan was approved by stockholders at the
Company’s annual stockholders’ meeting May 21, 2008. Awards
granted in 2008, 2007, and 2006 under the 2006 Equity Plan and the
Predecessor Plans were 932,767, 135,138, and 547,678,
respectively.
|
(2)
|
Under
the St. Mary Land & Exploration Company Employee Stock Purchase Plan
(the “ESPP”), eligible employees may purchase shares of the Company’s
common stock through payroll deductions of up to 15 percent of their
eligible compensation. The purchase price of the stock is 85
percent of the lower of the fair market value of the stock on the first or
last day of the purchase period, and shares issued under the ESPP are
restricted for a period of 18 months from the date issued. The
ESPP is intended to qualify under Section 423 of the Internal Revenue
Code. Shares issued under the ESPP totaled 45,228, 29,534, and
26,046 in 2008, 2007, and 2006,
respectively.
|
Years
Ended December 31,
|
|||||||||||||||
2008
|
2007
|
2006
|
2005
|
2004
|
|||||||||||
(In
thousands, except per share data)
|
|||||||||||||||
Total
operating revenues
|
$ | 1,301,301 | $ | 990,094 | $ | 787,701 | $ | 739,590 | $ | 433,099 | |||||
Net
income
|
$ | 91,553 | $ | 189,712 | $ | 190,015 | $ | 151,936 | $ | 92,479 | |||||
Net
income per share:
|
|||||||||||||||
Basic
|
$ | 1.47 | $ | 3.07 | $ | 3.38 | $ | 2.67 | $ | 1.60 | |||||
Diluted
|
$ | 1.45 | $ | 2.94 | $ | 2.94 | $ | 2.33 | $ | 1.44 | |||||
Total
assets at year end
|
$ | 2,695,016 | $ | 2,571,680 | $ | 1,899,097 | $ | 1,268,747 | $ | 945,460 | |||||
Long-term
obligations:
|
|||||||||||||||
Line
of credit
|
$ | 300,000 | $ | 285,000 | $ | 334,000 | $ | - | $ | 37,000 | |||||
Senior
convertible notes
|
$ | 287,500 | $ | 287,500 | $ | 99,980 | $ | 99,885 | $ | 99,791 | |||||
Cash
dividends declared and paid per common share
|
$ | 0.10 | $ | 0.10 | $ | 0.10 | $ | 0.10 | $ | 0.05 |
Supplemental
Selected Financial and Operations Data
|
|||||||||||||||
Years
Ended December 31,
|
|||||||||||||||
2008
|
2007
|
2006
|
2005
|
2004
|
|||||||||||
(In
thousands, except per share data)
|
|||||||||||||||
Balance
Sheet Data
|
|||||||||||||||
Total
working capital (deficit)
|
$ | 15,193 | $ | (92,604 | ) | $ | 22,870 | $ | 4,937 | $ | 12,035 | ||||
Total
stockholders’ equity
|
$ | 1,127,485 | $ | 863,345 | $ | 743,374 | $ | 569,320 | $ | 484,455 | |||||
Weighted-average
shares outstanding
|
|||||||||||||||
Basic
|
62,243 | 61,852 | 56,291 | 56,907 | 57,702 | ||||||||||
Diluted
|
63,133 | 64,850 | 65,962 | 66,894 | 66,894 | ||||||||||
Reserves
|
|||||||||||||||
Oil
(MMBbl)
|
51.4 | 78.8 | 74.2 | 62.9 | 56.6 | ||||||||||
Gas
(Mcf)
|
557.4 | 613.5 | 482.5 | 417.1 | 319.2 | ||||||||||
MCFE
|
865.5 | 1,086.5 | 927.6 | 794.5 | 658.6 | ||||||||||
Production
and Operational:
|
|||||||||||||||
Oil
and gas production revenues, including hedging
|
$ | 1,158,304 | $ | 936,577 | $ | 758,913 | $ | 711,005 | $ | 413,318 | |||||
Oil
and gas production expenses
|
$ | 271,355 | $ | 218,208 | $ | 176,590 | $ | 142,873 | $ | 95,518 | |||||
DD&A
|
$ | 314,330 | $ | 227,596 | $ | 154,522 | $ | 132,758 | $ | 92,223 | |||||
General
and administrative
|
$ | 79,503 | $ | 60,149 | $ | 38,873 | $ | 32,756 | $ | 22,004 | |||||
Production
Volumes:
|
|||||||||||||||
Oil
(MMBbl)
|
6.6 | 6.9 | 6.1 | 5.9 | 4.8 | ||||||||||
Gas
(Bcf)
|
74.9 | 66.1 | 56.4 | 51.8 | 46.6 | ||||||||||
BCFE
|
114.6 | 107.5 | 92.8 | 87.4 | 75.4 | ||||||||||
Realized
price – pre hedging:
|
|||||||||||||||
Per
Bbl
|
$ | 92.99 | $ | 67.56 | $ | 59.33 | $ | 53.18 | $ | 39.77 | |||||
Per
Mcf
|
$ | 8.60 | $ | 6.74 | $ | 6.58 | $ | 8.08 | $ | 5.85 | |||||
Realized
price – net of hedging:
|
|||||||||||||||
Per
Bbl
|
$ | 75.59 | $ | 62.60 | $ | 56.60 | $ | 50.93 | $ | 32.53 | |||||
Per
Mcf
|
$ | 8.79 | $ | 7.63 | $ | 7.37 | $ | 7.90 | $ | 5.52 | |||||
Expense
per MCFE:
|
|||||||||||||||
LOE
|
$ | 1.46 | $ | 1.31 | $ | 1.25 | $ | 0.99 | $ | 0.81 | |||||
Transportation
|
$ | 0.19 | $ | 0.14 | $ | 0.12 | $ | 0.09 | $ | 0.10 | |||||
Production
taxes
|
$ | 0.71 | $ | 0.58 | $ | 0.54 | $ | 0.56 | $ | 0.36 | |||||
DD&A
|
$ | 2.74 | $ | 2.12 | $ | 1.67 | $ | 1.52 | $ | 1.22 | |||||
General
and administrative
|
$ | 0.69 | $ | 0.56 | $ | 0.42 | $ | 0.37 | $ | 0.29 | |||||
Cash
Flow:
|
|||||||||||||||
Provided
by operations
|
$ | 678,221 | $ | 630,792 | $ | 467,700 | $ | 409,379 | $ | 237,162 | |||||
Used
in investing
|
$ | (672,785 | ) | $ | (803,872 | ) | $ | (724,719 | ) | $ | (339,779 | ) | $ | (247,006 | ) |
Provided
by (used in) financing
|
$ | (42,815 | ) | $ | 215,126 | $ | 243,558 | $ | (61,093 | ) | $ | 1,435 | |||
·
|
Average
daily gas production of 204.7 MMcf per day was up 13 percent from
2007. Average daily oil production of 18.1 MBbl per day was
down 4 percent from 2007. Average total equivalent daily
production was 313.1 MMCFE which was an annual record for the
Company.
|
·
|
Estimated
proved reserves of 51.4 MMBbls of oil and 557.4 Bcf of natural gas, or
865.5 BCFE, as of December 31, 2008. This was a decrease of 20
percent from year-end 2007 proved reserves of 1,086.5 BCFE and
reflects the divestiture of 61.4 BCFE of non-strategic properties, 44.5
BCFE in downward performance revisions, and 199.7 BCFE of negative price
revisions.
|
·
|
Diluted
earnings per share for 2008 were $1.45 on net income of $91.6 million.
This reflects a decrease in net income when compared to
2007.
|
·
|
Cash
flow from operating activities of $678.2 million, an increase of eight
percent from 2007.
|
Reserve
Replacement Percentage
|
Finding
Cost per MCFE
|
|||||||||
Excluding
sales
|
Including
sales
|
Excluding
sales
|
Including
sales
|
|||||||
Drilling,
excluding performance and price revisions
|
148% | 95% | $ | 3.99 | $ | 6.25 | ||||
Drilling,
including performance revisions
|
110% | 56% | $ | 5.40 | $ | 10.57 | ||||
Drilling
and acquisitions, excluding performance and price
revisions
|
174% | 120% | $ | 3.67 | $ | 5.30 | ||||
Drilling
and acquisitions, including performance revisions
|
135% | 81% | $ | 4.72 | $ | 7.83 | ||||
Acquisitions
|
25% | N/A | $ | 1.77 | N/A | |||||
All-in,
excluding price revisions
|
135% | 81% | $ | 5.54 | $ | 9.18 | ||||
All-in,
including performance and price revisions
|
(39)% | (93)% | $ | (19.04 | ) | $ | (8.05 | ) |
Reserve
Replacement Percentage
|
Finding
Cost per MCFE
|
|||||||||
Excluding
sales
|
Including
sales
|
Excluding
sales
|
Including
sales
|
|||||||
Drilling,
excluding performance and price revisions
|
133% | 112% | $ | 4.48 | $ | 5.32 | ||||
Drilling,
including performance revisions
|
142% | 121% | $ | 4.20 | $ | 4.93 | ||||
Drilling
and acquisitions, excluding performance and price
revisions
|
204% | 183% | $ | 3.63 | $ | 4.05 | ||||
Drilling
and acquisitions, including performance revisions
|
213% | 192% | $ | 3.48 | $ | 3.86 | ||||
Acquisitions
|
71% | N/A | $ | 2.03 | N/A | |||||
All-in,
excluding price revisions
|
213% | 192% | $ | 3.87 | $ | 4.29 | ||||
All-in,
including performance and price revisions
|
144% | 123% | $ | 5.73 | $ | 6.71 |