ITEM 2.
MANAGEMENT’S DISCUSSION AND ANA
LYSIS OF FINANCIAL CON
DITION AND
RESULTS OF OPERATIONS
Overview
We are an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. Our primary production activity is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma, and Central Oklahoma. We also have minor oil and gas producing properties in the Appalachian Basin. Our Cherokee Basin and Central Oklahoma properties comprise our MidContinent area of operations.
The following discussion should be read together with the unaudited condensed consolidated financial statements and related notes included elsewhere herein and with our annual report on Form 10-K for the year ended December 31, 2013.
2014 Drilling Program and Production Update
Central Oklahoma
Oil production for the first half of the year averaged 403 net barrels per day, a 132% increase over the prior-year period.
C
apital spending for the
six months ended June 30, 2014, totaled $17.5 million
,
of which $12.4 million related to Central Oklahoma.
During the year, we have performed development workovers on
twelve
wells. The cost of the workovers totaled appro
ximately $3 million and we expect the return to
exceed 100%. During the second quarter, we drilled and completed the first planned horizontal well targeting the Hunton formation at a cost of
approximately $2.8 mi
llion. In July
we spent approximately
$150
,000
. Additionally, we spud
our second horizontal well in the Hunton formation at the end of the second quarter and spent approximat
ely $1.5 million. D
rilling
was completed
in mid-July at a
n
additional cost of
approximately
$1.5 million
.
Initial results have been positive, as the development workovers have increased production by approximately 17
0 net barrels of oil per day while
the first horizontal well recently peaked at over 600 Bbls of oil per day and has produced 14,000 Bbls since coming on production in late June.
On January 31
, 2014
, we purchased additional interests in producing properties we acquired in November 2013. The additional interests were purchased for $1.8 million, consisting of $900,000 cash and 725,806 shares of our common stoc
k. The acquisition included approximately
960 net
acres of leasehold mineral interests, including certain producing oil and gas properties and related wells. The additional interest added
approximately 20
net
barrels of oil per day. Additionally
, we have incurred
approximately $1.0 million on geological and geophysical costs in 2014.
On June 12, 2014, we entered into
a joint venture (“JV”) agreement with Silver Creek Oil and Gas, LLC (“Silver Creek”) covering approximately 17,900 gross
unproved
acres in Cleveland and Pottawatomie Counties in central Oklahoma. The JV included an acre for acre swap of approximately 3,800 total net acres. After the swap, the ownership split in the development area is 30% PostRock and 70% Silver Creek, with Silver Creek serving as the operator.
We also sold
approximately 1,150 net
acres to
Silver Creek for $466
,000 in cash.
For the
remainder of the year, we expect
to spend approximately
$14.5 million to
drill, or participate
in, four to five
additional horizontal wells targeting the Hunton and the Woodfor
d shale formations, at least one vertical well
targeting multipl
e zones, and three to four
additional development workovers in Central Oklahoma. Two of the Woodford wells will be drilled as a part of the recent joint venture with Silver Creek. Locations have been identified, and drilling operations are expected to begin in the third quarter.
As attractive opportuni
ties are identified
, additional capital may be directed towards further oil development in the region.
Cherokee Basin
Oil and gas
production for the first half of the year averaged
203 net barrels per day and
34.
9 net MMcf per day, respectively. On a year-to-date
economic equivalency basis
of 21:1
, production declined 11% from the prior-year period to an average of 39.2 net MMcfe per day. The decline in production was due to the natural decline of our gas wells as we have not undertaken any development projects in the Cherokee Bas
in over the past two years in favor or focusing
our capital on
higher-return
oil projects in Central Oklahoma.
One of our most
significant projects over the p
ast roughly 18 months has been the reconfiguration of our Cherokee Basin compression system. This project was designed to improve energy efficiency and reduce gathering and operating costs.
The project was completed
on
May 6, 2014 and the inception to date cost is $8.3
million
. The project is expected to result in total annual rental savings of $4.6 million and reduce fuel consumption by approximately 1.6 MMcf per day.
Three Months Ended June
30,
2013
Compared to
the Three Months Ended June 30,
2014
The following table presents financial and operating data for the periods indicated as follows:
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Three Months Ended June 30,
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|
Increase/
|
|
2013
|
|
2014
|
|
(Decrease)
|
|
($ in thousands except per unit data)
|
|
Natural gas sales
|
$
|
14,434
|
|
$
|
14,656
|
|
$
|
222
|
|
1.5
|
%
|
Crude oil sales
|
$
|
4,444
|
|
$
|
6,194
|
|
$
|
1,750
|
|
39.4
|
%
|
Production expense
|
$
|
10,702
|
|
$
|
10,564
|
|
$
|
(138)
|
|
(1.3)
|
%
|
General and administrative
|
$
|
4,259
|
|
$
|
3,499
|
|
$
|
(760)
|
|
(17.8)
|
%
|
Depreciation, depletion and amortization
|
$
|
6,693
|
|
$
|
7,357
|
|
$
|
664
|
|
9.9
|
%
|
Other income (expense)
|
$
|
8,899
|
|
$
|
(6,210)
|
|
$
|
(15,109)
|
|
*
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|
Sales Data - Volumes
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|
Natural gas sales (MMcf)
|
|
3,635
|
|
|
3,336
|
|
|
(299)
|
|
(8.2)
|
%
|
Oil sales (Bbls)
|
|
49,481
|
|
|
62,050
|
|
|
12,569
|
|
25.4
|
%
|
Total sales (MMcfe)
|
|
3,932
|
|
|
3,709
|
|
|
(223)
|
|
(5.7)
|
%
|
Average daily sales (MMcfe/d)
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|
43.2
|
|
|
40.8
|
|
|
(2.4)
|
|
(5.7)
|
%
|
Average Sales Price per Unit
|
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|
Natural gas (Mcf)
|
$
|
3.97
|
|
$
|
4.39
|
|
$
|
0.42
|
|
10.6
|
%
|
Oil (Bbl)
|
$
|
89.81
|
|
$
|
99.82
|
|
$
|
10.01
|
|
11.1
|
%
|
Natural gas equivalent (Mcfe)
|
$
|
4.80
|
|
$
|
5.62
|
|
$
|
0.82
|
|
17.1
|
%
|
Average Unit Costs per Mcfe
|
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|
Production expense
|
$
|
2.72
|
|
$
|
2.85
|
|
$
|
0.13
|
|
4.7
|
%
|
Depreciation, depletion and amortization
|
$
|
1.70
|
|
$
|
1.98
|
|
$
|
0.28
|
|
16.7
|
%
|
____________
* Not meaningful
Natural gas sales increased $222,000, or 1.5%, from $
14.4
million during the
three
months ended
June 30, 2013
, to $
14.7
million during the
three
months ended
June 30, 2014
. Higher natural gas prices resulted in increased revenues of $1.4 million while lower gas volumes partially offset that increase by $1.2 million. The decline in gas volumes resulted from the lack of gas developmen
t projects in the last two years
as we focus
our capital on
higher-return
oil projects in Central Oklahoma
. Our average realized natural gas price increased from $3.97 per Mcf for the
three
months ended
June 30, 2013
, to $4.39 per Mcf for the
three
months ended
June 30, 2014
.
Oil sales
increased $1.8
million
, or 39.4%, from $
4.4
million during the
three
months ended
June 30, 2013
, to $6.2 million during the
three
months ended
June 30, 2014
. Higher oil volumes resulted in increased revenues of $1.1 million while higher oil prices increased revenue by an additional $621,000. Our oil production has grown as a result of development activities that have focused on expanding oil production and reserves since mid-2012. Our average realized
oil price increased from $89.81
per barrel for the
three
months ended
June 30, 2013
, to $99.82
per barrel for the
three
months ended
June 30, 2014
.
Production expense, consisting of lease operating expenses, severance and ad valorem taxes (“production taxes”) and gathering expense, decreased by $138,000, or 1.3 %, from $
10.7
million during the
three
months ended
June 30, 2013
, to $10.6 million during the
three
months ended
June 30, 2014
.
Lease operating costs decreased $879,000 in
the
Cherokee Basin
primarily due to compressor cost savings as a result of our compressor optimization project. These decreases were
offset by an increase in lease operating and severance taxes in Central Oklahoma of $669,000 and $169,000, respectively
, as a result of higher production in the area
.
The remainder of the decrease related to lower production taxes in the Cherokee Basin.
Production costs were $2.
72
per Mcfe for the
three
months ended
June 30, 2013
, as compared to $2.85 per Mcfe for the
three
months ended
June 30, 2014
.
Depreciation, depletion and amortization increased $664,000, or 9.9%, from $6.7 million during the
three
months ended
June 30, 2013
, to $7.4 million during the
three
months ended
June 30, 2014
. On a per unit basis, we had an increase of $0.28 per Mcfe from $1.70 per Mcfe during the three months ended June 30, 2013, to $1.98 per Mcfe during the
three
months ended June 30, 2014. The increase was primarily a result of an increase in the depreciation rate which was partially offset by lower volumes.
General and administrative expenses decreased $760,000, or 17.8%, from $4.3 million during the three months ended June 30, 2013, to $3.5 million during the three months ended
June 30, 2014
.
Excluding a $528,000 charge stemming from a 2009 workman’s
compensation insurance audit that was expensed in the prior-year period, general and administrative expenses decreased by 6%. The decrease was large
ly due to decreased
non-cash
compensation
in the current period
.
Other income (expense) consists primarily of realized and unrealized gains or losses from derivative instruments, gain or loss from equity investment and net interest expe
nse. We recorded a realized loss
on our derivative contracts of $
1.3
million for the three months ended
June 30, 2013
, compared to a realized loss of $
1.9 million
for the three months ended
June 30, 2014
.
We recorded an unrealized gain from derivative instruments of $10.1 million and unrealized loss of $
894,000
for
the three
months ended
June 30, 2013 and 2014
, respectively. We
recorded a mark-to-market gain
of $
863,000 and
$
87,000
on our
investment in CEP
for the
three
months ended
June 30, 2013 and 2014
, respectively.
Interest expense, net, was $769,000
during the
three
months ended
June 30, 2013
, and $
3.5 million
during the
three
months ended
June 30, 2014
.
Excluding non-cash interest of $2.6 million related to our Series A Preferred Stock, interest expense, net was $915,000 in the 2014 period.
Six Months Ended June 30,
2013
Compared to the
Six Months Ended June 30,
2014
The following table presents financial and operating data for the periods indicated as follows:
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Six Months Ended June 30,
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Increase/
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2013
|
|
2014
|
|
(Decrease)
|
|
|
($ in thousands except per unit data)
|
|
Natural gas sales
|
$
|
26,876
|
|
$
|
30,619
|
|
$
|
3,743
|
|
13.9
|
%
|
Crude oil sales
|
$
|
7,401
|
|
$
|
11,299
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|
$
|
3,898
|
|
52.7
|
%
|
Production expense
|
$
|
20,477
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|
$
|
20,836
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|
$
|
359
|
|
1.8
|
%
|
General and administrative
|
$
|
7,805
|
|
$
|
7,410
|
|
$
|
(395)
|
|
(5.1)
|
%
|
Depreciation, depletion and amortization
|
$
|
13,121
|
|
$
|
14,259
|
|
$
|
1,138
|
|
8.7
|
%
|
Other income (expense)
|
$
|
4,732
|
|
$
|
(13,236)
|
|
$
|
(17,968)
|
|
*
|
|
Sales Data - Volumes
|
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|
|
|
|
|
|
|
|
Natural gas sales (MMcf)
|
|
7,355
|
|
|
6,594
|
|
|
(761)
|
|
(10.3)
|
%
|
Oil sales (Bbls)
|
|
82,160
|
|
|
115,636
|
|
|
33,476
|
|
40.7
|
%
|
Total sales (MMcfe)
|
|
7,848
|
|
|
7,288
|
|
|
(560)
|
|
(7.1)
|
%
|
Average daily sales (MMcfe/d)
|
|
43.4
|
|
|
40.3
|
|
|
(3.1)
|
|
(7.2)
|
%
|
Average Sales Price per Unit
|
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|
|
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|
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|
|
Natural gas (Mcf)
|
$
|
3.65
|
|
$
|
4.64
|
|
$
|
0.99
|
|
27.2
|
%
|
Oil (Bbl)
|
$
|
90.08
|
|
$
|
97.71
|
|
$
|
7.63
|
|
8.5
|
%
|
Natural gas equivalent (Mcfe)
|
$
|
4.37
|
|
$
|
5.75
|
|
$
|
1.38
|
|
31.6
|
%
|
Average Unit Costs per Mcfe
|
|
|
|
|
|
|
|
|
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|
|
Production expense
|
$
|
2.61
|
|
$
|
2.86
|
|
$
|
0.25
|
|
9.5
|
%
|
Depreciation, depletion and amortization
|
$
|
1.67
|
|
$
|
1.96
|
|
$
|
0.29
|
|
17.2
|
%
|
____________
* Not meaningful
Natural gas sales increased $
3.7 million
, or
13.9
%, from $
26.9
million during the
six months ended June 30,
2013, to $
30.6
million during the
six months ended June 30, 2014
. Higher natural gas prices resulted in increased revenues of $6.5 million while lower gas volumes partially offset that increase by $2.8 million. In addition to significant weather-related interruption in the first quarter of 2014, the decline in gas volumes resulted from the lack of gas development projects in the last two years
as
we focus our capital on higher-
return oil projects in Central Oklahoma
. Our average realized natural gas price increased from
$3.65
per Mcf for the
six months ended June 30, 2013
, to $
4.64
per Mcf for the
six months ended June 30, 2014
.
Oil sales increased $
3.9
million, or
52.7
%, from $
7.4
million during the
six months ended June 30, 2013
, to $
11.3
million during the
six months ended June 30, 2014
. Higher oil volumes resulted in increased revenues of $3.0 million while higher oil prices provided an additional increase of $882,000. Our average realized oil price increased from $
90.08
per barrel for the
six months ended June 30, 2013
, to $
97.71
per barrel for the
six months ended June 30, 2014
.
Production expense increased $
359,000
, or
1.8
%, from $
20.5
million for the
six months ended June 30, 2013
, to $20
.8
million for the
six months ended June 30, 2014
. The increase was primarily due to more production activity in Central Oklahoma which increased operating costs and severance taxes by $1.2 million and $269,000, respectively. This increase was offset by decreased operating costs
primarily
related to compressor cost savings in the Cherokee Basin of $1.0 million. Production costs were $2.61 per Mcfe for the six
months ended June 30, 2013, as compared to $2.86 per Mcfe for the six months ended June 30, 2014
.
Depreciation, depletion and amortization increased $1.1 million, or 8.7%, from $13.1 million during the
six
months ended
June 30, 2013
, to $14.3 million during the
six
months ended
June 30, 2014
. On a per unit basis, we had an increase of $
0.29
per Mcfe from $1.
67
per Mcfe during the
six months ended June 30, 2013
, to $
1.96
per Mcfe during the
six months ended June 30, 2014
. The increase was primarily a result of an increase in the depreciation rate which was partially offset by lower volumes.
General and administrative expenses decreased $395,000, or 5.1%, from $7.8 million during the six months ended June 30, 2013, to $7.4 million during the six months ended
June 30, 2014
. The decrease was mainly due to the $528,000 workman’s compensation charge in 2013 as discussed above. The remaining variance was due to higher legal, license, and board fees partially offset by lower compensation.
Other income (expense) consists primarily of realized and unrealized gains or losses from derivative instruments, gain from investment, and net i
nterest expense. We r
ealized loss
es
on our derivative contracts of $
2.2
million for the
six months ended June 30, 2013
, compared to $
4.4 million
for the
six months ended June 30, 2014
. U
nrealized gain
s
from derivative instruments of $
3.9
million
were recognized for the six months ended June 30, 2013
and an unrealized loss of $
3.5
million for the
six months ended
June 30,
2014
. We recorded a mark-to-market gain of $
4.4
million and $
1.7
million on our investment in CEP for the
six months ended June 30, 2013 and 2014
, respectively.
Interest expense, net, was $
1.4
million during the
six months ended June 30, 2013
, and $
7.0 million
during the
six months ended June 30, 2014
. Excluding
non-cash interest of $5.1 million related to our Series A Preferred Stock, interest expense, net was $1.9 million, higher compared to the prior period as a result of higher debt in the current period.
Liquidity and Capital Resources
Cash flows from operating activities have historically been driven by the quantities of our production and the prices received from the sale of our production. Prices of oil and gas have historically been very volatile and can significantly impact the cash received from the sale of our production. Use of derivative financial instruments helps mitigate this price volatility. Proceeds from or payments for derivative settlements are included in cash flows from operations. Cash expenses also impact our operating cash flow and consist primarily of production expenses, interest on our indebtedness and general and administrative expenses.
Our primary sources of liquidity for the six months ended June 30, 2014, were cash from operations, proceeds from our settlement of the CEP lawsuit and the subsequent sale of CEP Class B units. At
June 30, 2014
, our debt decreased by
$
5
.0
million from December 31, 2013. The de
crease was primarily due to
repayments under our credit facility,
utilizing proceeds from the sale of CEP settlement and subsequent sales of CEP Class B units.
Cash Flows from Operating Activities
Cash flows provided by operating activities were $
1.2
million for the
six months ended June 30, 201
3, compared to $8.5 million for the
six months ended June 30,
2014
. The increase in cash was primarily a result of an increase in revenues of $7.8 million from the prior year period as
realized commodity prices were
higher.
Cash Flows from Investing Activities
Cash flows used in investing activities were $
25.1
million for the
six months ended June 30, 2013
, compared to $
3.5
million for the
six months ended June 30, 2014
. The de
creased outflow was primarily
due to lower
capital expenditures
in the current period and by proceeds from the sale of CEP Class B units. Capital expenditures in the prior-year period were higher as a result of a higher number of oil development projects when compared to the number of projects in the current period. Acquisition and development c
apital expenditures in the current year refl
ect our expanded oil
activ
ity in
Central Oklahoma.
‘Other’ capital expenditures are mainly costs associated with our compressor optimization project in the Cherokee Basin.
The following table sets forth our capital expenditures, including costs we have incurred but not paid, by major categories for the
six
months ended
June 30, 2014
:
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|
Six Months Ended
|
|
June 30, 2014
|
|
(in thousands)
|
Capital expenditures
|
|
|
Acquisition
|
$
|
3,582
|
Development
|
|
9,137
|
Other
|
|
4,813
|
Total capital expenditures
|
$
|
17,532
|
Cash Flows from Financing Activities
Cash flows from financing activities were $
23.7
million for the
six months ended June 30, 2013
, as compared to cash flows used of $
5.0
million for the
six months ended June 30, 2014
. The difference in cash flows was primarily driven by debt borrowing in the prior year compared to repayments in the current year. Debt borrowings were $
20.0
million for the
six months ended June 30, 2013
, compared to repayments of $
5.0
million for the
six months ended June 30, 2014
. The repayments in the current year were facilitated by proceeds from the sale of our CEP Class B units. Also, during the six months ended June 30, 2013, we had proceeds from the issuance of common stock of $4.1 million.
Sources of Liquidity in 2014 and Capital Requirements
We rely on our cash flows from operating activities as a source of internally generated liquidity. Our long-term ability to generate liquidity internally depends, in part, on our ability to hedge future production at attractive prices as well as our ability to control operating expenses. In the first quarter of 2014, we settled our lawsuit with CEP and SEPI and used proceeds received to reduce bank debt. The settlement positions us to redeploy capital into oil-focused development projects primarily in Central Oklahoma. As of July 31, 2014, we had sold an
additional 1,116,984 CEP
Class B units at an average price
of $
2.70
and
we continued to
own 3,165,516 Class
B units which we intend to dispose of over the next six to nine months.
At June 30, 2014, we had a $200 million secured borrowing base revolving credit facility, which we use as an external source of long and short term liquidity. The borrowing base was redetermined on May 22, 2014 based on reserves at December 31, 2013 and remained unchanged at $115 million. The borrowing base is determined based on the value of our oil and natural gas reserves at our lenders’ forward price forecasts, which are generally derived from futures price
s. The redetermination was also adjusted to reflect our recent acquisition of oil and gas properties in Central Oklahoma.
With outstanding borrowings of $
8
7.0 million and letters of credit
of
$1.
4
million, $
26.6 million was available for additional borrowings at
June 30, 2014
. The terms of the Borrowing Base Facility are described within Note 10 of Item 8. Financial Statement and Supplementary Data in our annual report on Form 10-K for the year ended December 31, 2013. With the current availability under our borrowing base facility, expected cash flows from operations and expected proceeds from further sales of CEP Class B units, we believe that we have sufficient liquidity to fund our capital expenditures and financial obligations for the next 12 months.
Dilution
At
June 30, 2014
, including
10,958,601
shares of our common stock held by White Deer, we had
30,777,181
shares of common stock outstanding. In addition, we had
24,903,781
outstanding warrants to purchase our common stock of which
24,679,173
are owned by White Deer at an average exercise price of $
1.51
and
224,608
are owned by Constellation Energy Group Inc. at an average exercise price of $
7
.
57
.
The warrants held by Constellation Energy Group expire on August 8, 2014.
We also had
162,451
restricted stock units and
2,671,119
options outstanding granted under our long-term incentive plan. Consequently, if these securities were included as outstanding, our outstanding shares would have been 58,352,081 of which the warrants and common stock owned by White Deer would represent approximately
61
%. By exercising its
warrants, W
hite Deer can benefit from its
respective percentage of all of our profits and growth. In addition, if White Deer begins to sell significant amounts of our common stock, or if p
ublic markets perceive that it
may sell significant amounts of our common stock, the market price of our common stock may be significantly impacted.
We have an effective universal shelf registration statement on Form S-3. Pursuant to the registration statement, we implemented an at-the-market program under which shares of our common stock can be sold. There were no sales of common stock in the first half of the year.
Contractual Obligations
We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases and purchase obligations. During the six months ended June 30, 2014, we entered into new contractual commitments for compressors.
As
a result,
the $
7.2
million
minimum amount of these contracts over a span of
five
years would be an increase to the amount included in our outstanding contractual commitments table at December 31, 2013.
Other than the contractual commitments discussed above and debt repayments during the
six months ended June 30, 2014
, there were no material changes to the our contractual commitments since December 31, 2013.
Forward-Looking Statements
Various statements in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements include those regarding projections and estimates concerning the timing and success of specific projects; financial position; business strategy; budgets; amount, nature and timing of capital expenditures; drilling of wells and construction of pipeline infrastructure; acquisition and development of oil and natural gas properties and related pipeline infrastructure; timing and amount of future production of oil and natural gas; operating costs and other expenses; estimated future net revenues from oil and natural gas reserves and the present value thereof; cash flow and anticipated liquidity; funding of our capital expenditures; ability to meet our debt service obligations; and other plans and objectives for future operations.
When we use the words “believe,” “intend,” “expect,” “may,” “will,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The factors impacting these risks and uncertainties include, but are not limited to:
•
current weak economic conditions;
•
volatility of oil and natural gas prices;
•
increases in the cost of drilling, completion and gas gathering or other costs of developing and producing our reserves;
•
our debt covenants;
•
access to capital, including debt and equity markets;
•
results of our hedging activities;
•
drilling, operational and environmental risks; and
•
regulatory changes and litigation risks.
You should consider carefully the statements under Item 1A. Risk Factors included in our annual report on Form 10-K for the year ended December 31, 2013, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.
We have based these forward-looking statements on our current expectations and assumptions about future events. The forward-looking statements in this report speak only as of the date of this report; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the SEC, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.