Contango Announces Third Quarter 2018 Financial Results and Provides Operational Update
HOUSTON, Nov. 07, 2018 (GLOBE NEWSWIRE) -- Contango Oil & Gas Company (NYSE American: MCF) (“Contango,” the “Company,” “we” or “us”) announced today its financial results for the third quarter ended September 30, 2018 and provided an operational update.
Management Commentary
Wilkie S. Colyer, the Company’s newly appointed President and Chief Executive Officer, said “In mid-August, we changed the composition of the board and executive team so that insiders became by far the largest shareholders of the Company. We believe this is the best possible way to align our interests with those of all stakeholders. We have identified several strategic initiatives that we believe will drive long term shareholder value and have begun to execute upon several of these initiatives, including a focus on significant cost reduction, enhanced hedging of our PDP, particularly in the Gulf of Mexico, greater discipline and focus on returns on capital, evaluation of non-core asset sales, including potentially our Pecos County midstream assets, and evaluation of opportunities to strategically expand our reserves where we see attractive risk-adjusted returns. We have over a decade of drilling inventory in Pecos County and the operational expertise to develop it. I am excited about the opportunity in front of us and look forward to working with our team to create value for shareholders. As part of this ongoing effort, we have engaged a financial advisor, Intrepid Partners, to assist the Board in evaluating strategic alternatives available to the Company.”
Summary Third Quarter Financial Results
Net loss for the three months ended September 30, 2018 was $81.5 million, or $3.26 per basic and diluted share, compared to a net loss of $6.9 million, or $0.28 per basic and diluted share, for the same period last year. Impacting our earnings this quarter was $72.5 million in pre-tax, non-cash impairment and abandonment charges which included the impairment of the carrying costs of our Gulf of Mexico properties due to revised proved reserve estimates made during the quarter and the impairment of the carrying costs of certain non-core properties in Southeast Texas related to reducing such properties to their fair value as a result of a planned sale. Excluding impairment and abandonment charges, our pre-tax net loss for the current quarter would have been $9.0 million, compared to a pre-tax net loss of $6.8 million for the prior year quarter, as higher revenues and lower operating expenses were overshadowed by higher depreciation expense resulting from the reserve revisions and a larger loss on our outstanding derivatives. Average weighted shares outstanding were approximately 25.0 million and 24.7 million for the current and prior year quarters, respectively.
The Company reported Adjusted EBITDAX, as defined below, of approximately $6.2 million for the three months ended September 30, 2018, compared to $7.5 million for the same period last year, as higher revenues and lower salaries and other compensation costs were more than offset by higher realized losses on our derivatives due to higher commodity prices, and severance benefits attributable to the resignation of our former President and CEO in September 2018. Cash flow for the current quarter was $4.8 million, or $0.19 per share, compared to $6.4 million, or $0.26 per share for the prior year quarter.
Revenues for the current quarter were approximately $19.5 million compared to $18.8 million for the third quarter of 2017. This increase was attributable to the increase in crude oil and natural gas liquids prices during the quarter, offset in part by lower production resulting from just three new wells being added to production during the quarter. Revenue from crude oil increased to $8.6 million for the current quarter, compared to $6.1 million for the prior year quarter due to higher crude oil production from our Southern Delaware drilling program and higher crude oil prices.
Production for the third quarter of 2018 was approximately 4.0 billion cubic feet equivalent (“Bcfe”), or 43.6 million cubic feet equivalent per day (“Mmcfed”), within our previously provided guidance, compared to 53.2 Mmcfed for the third quarter of 2017. This expected year over year decline in production from gas properties was partially offset by new West Texas oil production. Our production guidance for the fourth quarter of 2018 is between 39 to 44 Mmcfed as our gas weighted offshore production was slightly curtailed in October due to compressor issues which have subsequently been fixed.
The weighted average equivalent sales price during the three months ended September 30, 2018 was $4.86 per thousand cubic feet equivalent (“Mcfe”), compared to $3.84 per Mcfe for the same period last year, as a slight decline in natural gas prices was offset by increases of 34% and 37% in crude oil and natural gas liquids prices, respectively, compared to the prior year quarter, and due to the increase in the higher percentage of oil and natural gas liquids in the production mix.
Operating expenses for the three months ended September 30, 2018 were approximately $6.4 million, or $1.59 per Mcfe, compared to $7.0 million, or $1.44 per Mcfe, for the same period last year. Included in operating expenses are direct lease operating expenses, transportation and processing costs, workover expenses and production and ad valorem taxes. Operating expenses exclusive of production and ad valorem taxes were approximately $5.6 million, or $1.39 per Mcfe, for the current quarter, compared to $6.4 million, or $1.31 per Mcfe for the prior year quarter and within our previously provided guidance for the current quarter. Our guidance for operating expenses for the fourth quarter of 2018, exclusive of production and ad valorem taxes, is between $5.8 to $6.4 million due to an estimated $0.5 million in scheduled workovers.
DD&A expense for the three months ended September 30, 2018 was $12.9 million, or $3.20 per Mcfe, compared to $11.2 million, or $2.28 per Mcfe, for the prior year quarter, an increase attributable primarily to the higher depletion rate, calculated as a percentage of production to estimated reserves, as a result of the downward revision of offshore reserve estimates. Our DD&A rate guidance for the fourth quarter of 2018 is between $2.40 - $2.65 per Mcfe, a decrease that reflects the impact of the Eugene Island impairment charge taken in this quarter.
Impairment and abandonment expense of oil and gas properties was $72.5 million for the current quarter, including $59.4 million of proved property non-cash impairment of carrying costs of our Gulf of Mexico properties as a result of revised proved reserve estimates prepared by our third-party engineers and $12.8 million of proved property non-cash impairment of carrying costs of certain non-core properties in Southeast Texas related to reducing such properties to their fair value as a result of a planned sale.
Total G&A expenses, inclusive of stock compensation expense, were $6.7 million in the current quarter, compared to $6.2 million, for the prior year quarter. Cash G&A expenses, i.e., total G&A expenses exclusive of stock compensation expense of $0.7 million and $1.5 million for the third quarter of 2018 and 2017, respectively, was $6.0 million, or $1.48 per Mcfe for the current quarter, compared to $4.7 million, or $0.97 per Mcfe for the prior year quarter, as a $0.9 million reduction in salaries and accrued performance bonuses was offset by a $1.8 million severance accrual attributable to the resignation of our former President and CEO in September 2018. For the fourth quarter of 2018, we have provided guidance of $4.0 to $4.5 million for cash general and administrative expenses.
Loss from affiliates (i.e., Exaro Energy III) for the three months ended September 30, 2018 was approximately $0.3 million, compared to a gain of $0.5 million for the same period last year due to unrealized losses on gas derivatives Exaro Energy III had in place for the current year quarter.
Gain from sale of assets for the three months ended September 30, 2018 was approximately $0.5 million, which related to the sale of energy credits to a third party.
Loss on derivatives for the three months ended September 30, 2018 was approximately $1.3 million. Of this amount, $1.1 million were realized losses while the remaining $0.2 million were non-cash, unrealized mark-to-market losses. There was no meaningful gain or loss on derivatives for the three months ended September 30, 2017.
Drilling Activity Update
Our recent Southern Delaware Basin activity consists of the following:
Fighting Ace #2H
In September 2018, we began production from the Fighting Ace #2H (50% WI, 38% NRI) targeting the Wolfcamp A, which was drilled to a TMD of 20,560 feet, including a 10,598 foot lateral. This well had a maximum 30-day IP rate of 656 barrels of oil equivalent per day (“Boed”) (71% oil).
General Paxton #1H
On August 2, 2018, we spud the General Paxton #1H (50% WI, 38% NRI) in the southeast quadrant of our acreage position. This well also targeted the Wolfcamp A formation and was drilled to a TMD of approximately 20,145 feet, including a lateral of approximately 10,392 feet, and had a 24-hour IP of 1,129 Boed (81% oil) and a 30-day IP rate of 981 Boed (79% oil). This well has the highest oil cut of any other well we have drilled in the area.
Ripper State #2H
On August 31, we spud the Ripper State #2H (50% WI, 38% NRI) targeting the Wolfcamp B formation. This well was drilled to a TMD of approximately 20,545 feet, including a lateral of approximately 10,179 feet. Completion operations will begin at a later date.
Capital Program and Liquidity
Capital costs incurred for the current quarter were approximately $15.9 million, nearly all of which was related to our Southern Delaware Basin play in Pecos County, Texas. For the remainder of 2018, we have not budgeted to spend any significant amount of capital as we intend to reduce our pace of development in the Southern Delaware while the Midland-Cushing oil price differential in the region stabilizes and will use this time to both further evaluate well results and offset operator activity while infrastructure continues to develop in the area and to reduce outstanding debt through a reduction in general and administrative costs. Any further drilling during 2018 will be as necessary to maintain our Southern Delaware Basin acreage position.
As of September 30, 2018, we had approximately $81.8 million of debt outstanding under our credit facility. On November 2, 2018, we entered into the Sixth Amendment to the RBC Credit Facility (the “Sixth Amendment”) whereby the current borrowing base was reaffirmed at $105 million and will be reduced to $90 million on and after January 31, 2019, unless such reduction is waived by all lenders.
The Sixth Amendment also provides for, among other things: (i) waiving compliance with the required minimum 1.00 to 1.00 Current Ratio for the fiscal quarters ended September 30, 2018 and December 31, 2018; and (ii) eliminating an exception from the restriction on payment of dividends, stock repurchases or redemptions of equity for repurchases under certain circumstances.
Derivative Instruments
We had the following financial derivative contracts in place at September 30, 2018:
Commodity
Period
Derivative
Volume/Month
Price/Unit
Natural Gas
Oct 2018
Swap
70,000 MMBtus
$
3.07 (1)
Natural Gas
Nov 2018 - Dec 2018
Swap
320,000 MMBtus
$
3.07 (1)
Oil
Oct 2018
Collar
20,000 Bbls
$
52.00 - 56.85 (2)
Oil
Nov 2018 - Dec 2018
Collar
15,000 Bbls
$
52.00 - 56.85 (2)
Oil
Oct 2018 - Dec 2018
Collar
2,000 Bbls
$
52.00 - 58.76 (3)
Oil
Nov 2018 - Dec 2018
Collar
5,000 Bbls
$
58.00 - 68.00 (2)
Oil
Oct 2018
Swap
3,000 Bbls
$
70.11 (3)
Oil
Nov 2018 - Dec 2018
Swap
6,000 Bbls
$
70.11 (3)
Oil
Jan 2019 - Dec 2019
Collar
4,000 Bbls
$
52.00 - 59.45 (3)
Oil
Jan 2019 - Dec 2019
Collar
7,000 Bbls
$
50.00 - 58.00 (2)
Oil
Jan 2019 - July 2019
Swap
6,000 Bbls
$
66.10 (3)
Based on Henry Hub NYMEX natural gas prices.
Based on Argus Louisiana Light Sweet crude oil prices.
Based on West Texas Intermediate crude oil prices.
We entered into the following financial derivative contracts in October 2018:
Commodity
Period
Derivative
Volume/Month
Price/Unit
Natural Gas
Nov 2018 - Dec 2018
Swap
200,000 MMBtus
$
3.35 (1)
Natural Gas
Nov 2018 - Dec 2018
Swap
100,000 MMBtus
$
3.21 (1)
Natural Gas
Jan 2019 - Mar 2019
Swap
600,000 MMBtus
$
3.21 (1)
Natural Gas
Apr 2019 - July 2019
Swap
600,000 MMBtus
$
2.75 (1)
Natural Gas
Aug 2019 - Oct 2019
Swap
100,000 MMBtus
$
2.75 (1)
Natural Gas
Nov 2019 - Dec 2019
Swap
500,000 MMBtus
$
2.75 (1)
Oil
Nov 2018 - Dec 2018
Collar
7,000 Bbls
$
70.00 - 77.65 (2)
Oil
Jan 2019 - June 2019
Collar
12,000 Bbls
$
70.00 - 76.25 (2)
Oil
July 2019
Swap
12,000 Bbls
72.10 (2)
Oil
Aug 2019 - Oct 2019
Swap
9,000 Bbls
72.10 (2)
Oil
Nov 2019 - Dec 2019
Swap
12,000 Bbls
72.10 (2)
Based on Henry Hub NYMEX natural gas prices.
Based on West Texas Intermediate crude oil prices.
Selected Financial and Operating Data The following table reflects certain comparative financial and operating data for the three and nine months ended September 30, 2018 and 2017:
Three Months Ended
Nine months ended
September 30,
September 30,
2018
2017
%
2018
2017
%
Offshore Volumes Sold:
Oil and condensate (Mbbls)
20
23
-13
%
56
78
-28
%
Natural gas (Mmcf)
1,943
2,702
-28
%
5,934
8,618
-31
%
Natural gas liquids (Mbbls)
74
87
-15
%
211
254
-17
%
Natural gas equivalents (Mmcfe)
2,505
3,360
-25
%
7,538
10,608
-29
%
Onshore Volumes Sold:
Oil and condensate (Mbbls)
118
109
8
%
374
310
21
%
Natural gas (Mmcf)
518
613
-15
%
1,719
2,032
-15
%
Natural gas liquids (Mbbls)
47
45
4
%
146
143
2
%
Natural gas equivalents (Mmcfe)
1,510
1,541
-2
%
4,835
4,751
2
%
Total Volumes Sold:
Oil and condensate (Mbbls)
138
132
5
%
430
388
11
%
Natural gas (Mmcf)
2,461
3,315
-26
%
7,653
10,650
-28
%
Natural gas liquids (Mbbls)
121
132
-8
%
357
397
-10
%
Natural gas equivalents (Mmcfe)
4,015
4,901
-18
%
12,373
15,359
-19
%
Daily Sales Volumes:
Oil and condensate (Mbbls)
1.5
1.4
5
%
1.6
1.4
11
%
Natural gas (Mmcf)
26.7
36.0
-26
%
28.0
39.0
-28
%
Natural gas liquids (Mbbls)
1.3
1.4
-8
%
1.3
1.5
-10
%
Natural gas equivalents (Mmcfe)
43.6
53.2
-18
%
45.3
56.3
-19
%
Average sales prices:
Oil and condensate (per Bbl)
$
61.92
$
46.30
34
%
$
62.76
$
46.76
34
%
Natural gas (per Mcf)
$
2.90
$
2.92
-1
%
$
2.82
$
3.00
-6
%
Natural gas liquids (per Bbl)
$
31.59
$
22.98
37
%
$
27.45
$
21.26
29
%
Total (per Mcfe)
$
4.86
$
3.84
27
%
$
4.72
$
3.81
24
%
Three Months Ended
Nine Months Ended
September 30,
September 30,
2018
2017
%
2018
2017
%
Offshore Selected Costs ($ per Mcfe)
Lease operating expenses (1)
$
0.80
$
0.83
-4
%
$
0.85
$
0.75
13
%
Production and ad valorem taxes
$
0.08
$
0.05
60
%
$
0.07
$
0.06
17
%
Onshore Selected Costs ($ per Mcfe)
Lease operating expenses (1)
$
2.38
$
2.36
1
%
$
2.26
$
2.17
4
%
Production and ad valorem taxes
$
0.40
$
0.30
33
%
$
0.38
$
0.30
27
%
Average Selected Costs ($ per Mcfe)
Lease operating expenses (1)
$
1.39
$
1.31
6
%
$
1.40
$
1.19
18
%
Production and ad valorem taxes
$
0.20
$
0.13
54
%
$
0.20
$
0.13
54
%
General and administrative expense (cash)
$
1.48
$
0.97
53
%
$
1.21
$
0.92
32
%
Interest expense
$
0.35
$
0.23
52
%
$
0.33
$
0.18
83
%
Adjusted EBITDAX (2) (thousands)
$
6,205
$
7,489
$
21,950
$
24,874
Weighted Average Shares Outstanding (thousands)
Basic
25,001
24,708
24,910
24,662
Diluted
25,001
24,708
24,910
24,662
LOE includes transportation and workover expenses.
Adjusted EBITDAX is a non-GAAP financial measure. See below for reconciliation to net income.
CONTANGO OIL & GAS COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands)
September 30,
December 31,
2018
2017
ASSETS
(unaudited)
Cash and cash equivalents
$
—
$
—
Accounts receivable, net
10,957
13,059
Other current assets
2,982
2,714
Net property and equipment
270,956
345,957
Investment in affiliates and other non-current assets
19,366
19,723
TOTAL ASSETS
$
304,261
$
381,453
LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts payable and accrued liabilities
52,899
46,755
Other current liabilities
5,305
3,782
Long-term debt
81,771
85,380
Asset retirement obligations
17,837
20,388
Other non-current liabilities
6,212
548
Total shareholders’ equity
140,237
224,600
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY
$
304,261
$
381,453
CONTANGO OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands)
Three Months Ended
Nine Months Ended
September 30,
September 30,
2018
2017
2018
2017
(unaudited)
REVENUES
Oil and condensate sales
$
8,558
$
6,109
$
26,976
$
18,134
Natural gas sales
7,128
9,681
21,585
31,956
Natural gas liquids sales
3,822
3,040
9,832
8,440
Total revenues
19,508
18,830
58,393
58,530
EXPENSES
Operating expenses
6,382
7,041
19,787
20,203
Exploration expenses
425
315
1,288
690
Depreciation, depletion and amortization
12,853
11,193
32,836
35,678
Impairment and abandonment of oil and gas properties
72,524
84
76,628
1,515
General and administrative expenses
6,724
6,219
18,804
18,648
Total expenses
98,908
24,852
149,343
76,734
OTHER INCOME (EXPENSE)
Gain (loss) from investment in affiliates, net of income taxes
(270
)
525
(38
)
2,475
Gain (loss) from sale of assets
498
(184
)
11,315
2,336
Interest expense
(1,411
)
(1,138
)
(4,082
)
(2,822
)
Gain (loss) on derivatives, net
(1,319
)
(9
)
(4,961
)
4,574
Other income (expense)
357
—
1,239
(27
)
Total other income (expense)
(2,145
)
(806
)
3,473
6,536
NET LOSS BEFORE INCOME TAXES
(81,545
)
(6,828
)
(87,477
)
(11,668
)
Income tax benefit (provision)
21
(88
)
(288
)
(397
)
NET LOSS
$
(81,524
)
$
(6,916
)
$
(87,765
)
$
(12,065
)
Non-GAAP Financial Measures
This news release includes certain non-GAAP financial information as defined by Securities and Exchange Commission rules. Pursuant to SEC requirements, reconciliations of non-GAAP financial measures to the most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles (GAAP) are included in this press release.
EBITDAX represents net income (loss) before interest expense, taxes, and depreciation, depletion and amortization, and oil & gas exploration expenses. Adjusted EBITDAX represents EBITDAX as further adjusted to reflect the items set forth in the table below and is a measure required to be used in determining our compliance with financial covenants under our credit facility.
We have included EBITDAX and Adjusted EBITDAX in this release to provide investors with a supplemental measure of our operating performance and information about the calculation of some of the financial covenants that are contained in our credit agreement. We believe EBITDAX is an important supplemental measure of operating performance because it eliminates items that have less bearing on our operating performance and therefore highlights trends in our core business that may not otherwise be apparent when relying solely on GAAP financial measures. We also believe that securities analysts, investors and other interested parties frequently use EBITDAX in the evaluation of companies, many of which present EBITDAX when reporting their results. Adjusted EBITDAX is a material component of the covenants that are imposed on us by our credit agreement. We are subject to financial covenant ratios that are calculated by reference to Adjusted EBITDAX. Non-compliance with the financial covenants contained in our credit agreement could result in a default, an acceleration in the repayment of amounts outstanding and a termination of lending commitments. Our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, also use EBITDAX and Adjusted EBITDAX to assess:
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;
our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and
the feasibility of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
In addition to EBITDAX and Adjusted EBITDAX, we may provide additional non-GAAP financial measures because our management believes providing investors with this information gives additional insights into our profitability, cash flows and expenses.
EBITDAX and Adjusted EBITDAX and other non-GAAP measures in this release are not presentations made in accordance with generally accepted accounting principles, or GAAP. As discussed above, we believe that the presentation of non-GAAP financial measures in this release is appropriate. However, when evaluating our results, you should not consider the non-GAAP financial measures in isolation of, or as a substitute for, measures of our financial performance as determined in accordance with GAAP, such as net income (loss). For example, EBITDAX and Adjusted EBITDAX have material limitations as performance measures because they exclude items that are necessary elements of our costs and operations. Because other companies may calculate EBITDAX and Adjusted EBITDAX differently than we do, EBITDAX may not be, and Adjusted EBITDAX as presented in this release is not, comparable to similarly-titled measures reported by other companies.
The following table reconciles net income to EBITDAX and Adjusted EBITDAX for the periods presented:
Three Months Ended
Nine Months Ended
September 30,
September 30,
2018
2017
2018
2017
(in thousands)
Net loss
$
(81,524
)
$
(6,916
)
$
(87,765
)
$
(12,065
)
Interest expense
1,411
1,138
4,082
2,822
Income tax provision (benefit)
(21
)
88
288
397
Depreciation, depletion and amortization
12,853
11,193
32,836
35,678
Exploration expense
425
315
1,288
690
EBITDAX
$
(66,856
)
$
5,818
$
(49,271
)
$
27,522
Unrealized loss (gain) on derivative instruments
$
240
$
530
$
2,551
$
(3,797
)
Non-cash stock-based compensation charges
764
1,482
3,772
4,560
Impairment of oil and gas properties
72,285
—
76,175
1,400
Gain on sale of assets and investment in affiliates
(228
)
(341
)
(11,277
)
(4,811
)
Adjusted EBITDAX
$
6,205
$
7,489
$
21,950
$
24,874
Guidance for Fourth Quarter 2018
The Company is providing the following guidance for the fourth calendar quarter of 2018.
Production
39,000 - 44,000 Mcfe per day
LOE (including transportation and workovers)
$5.8 million - $6.4 million
Production and ad valorem taxes (% of Revenue)
3.75% - 4.25%
Cash G&A
$4.0 million - $4.5 million
DD&A Rate
$2.40 - $2.65
Teleconference Call
Contango management will hold a conference call to discuss the information described in this press release on Thursday, November 8, 2018 at 8:00 am Central Standard Time. Those interested in participating in the earnings conference call may do so by calling the following phone number: 1-800-230-1085, (International 1-612-288-0337), and entering access code 456608. A replay of the call will be available from Thursday, November 8, 2018 at 10:00 am CST through Thursday, November 15, 2018 at 11:59 pm CST by calling the following phone number: 1-800-475-6701, (International 1-320-365-3844), and entering access code 456608.
About Contango Oil & Gas Company
Contango Oil & Gas Company is a Houston, Texas based, independent oil and natural gas company whose business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico and onshore properties in Texas and Wyoming and to use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties in West Texas, the Texas Gulf Coast and the Rocky Mountain regions of the United States. Additional information is available on the Company's website at http://contango.com.
Forward-Looking Statements and Cautionary Statements
This press release contains 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, as amended. These statements are, based on Contango’s current expectations and includes statements regarding our estimates of future production, and other guidance (including information regarding lease operating expenses, cash G&A expenses, and DD&A Rate), acquisitions and divestitures, future results of operations, quality and nature of the asset base, the assumptions upon which estimates are based and other expectations, beliefs, plans, objectives, assumptions, strategies or statements about future events or performance. Words and phrases used to identify our forward-looking statements include terms such as “guidance”, "expects", “projects”, "anticipates", "plans", "estimates", "potential", "possible", "probable", or "intends", or words and phrases stating that certain actions, events or results "may", "will", "should", or "could" be taken, occur or be achieved. Statements concerning oil and gas reserves also may be deemed to be forward looking statements in that they reflect estimates based on certain assumptions that the resources involved can be economically exploited. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those, reflected in the statements. These risks include, but are not limited to: the risks of the oil and gas industry (for example, operational risks in exploring for, developing and producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; health, safety and environmental risks and risks related to weather such as hurricanes and other natural disasters); uncertainties as to the availability and cost of financing; our ability to comply with financial covenants in our debt instruments, repay indebtedness and access new sources of indebtedness, including our ability to refinance and/or replace the existing RBC Credit Facility, provide additional liquidity for future capital expenditures and/or continue as a going concern; fluctuations in oil and gas prices; risks associated with derivative positions; our ability to realize expected value from acquisitions and to complete strategic dispositions of assets and realize the benefits of such dispositions; the need to take impairments on properties due to lower commodity prices; the limited trading volume of our common stock and general market volatility; ability of our management team to execute its plans or to meet its goals; shortages of drilling equipment, oil field personnel and services; unavailability of gathering systems, pipelines and processing facilities; the possibility that government policies may change or governmental approvals may be delayed or withheld; and the other factors discussed under the “Risk Factors” heading in our most recent annual report on Form 10-K and our quarterly reports on Form 10-Q filed with or furnished to the Securities and Exchange Commission. Additional information on these and other factors which could affect Contango’s operations or financial results are included in Contango’s reports on file with the Securities and Exchange Commission. Investors are cautioned that any forward-looking statements are not guarantees of future performance and actual results or developments may differ materially from the projections in the forward-looking statements. Forward-looking statements speak only as of the date they were made and are based on the estimates and opinions of management at the time the statements are made. Contango does not assume any obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.
Cautionary Statements Regarding Reserves
The estimates and guidance presented in this release are based on assumptions of capital expenditure levels, prices for oil, natural gas and NGLs, current indications of supply and demand for oil, well results and operating costs. IP and other production rates included in this release might not be indicative of production over longer periods in the life of the well. The guidance provided in this release does not constitute any form of guarantee or assurance that the matters indicated will be achieved. While we believe these estimates and the assumptions on which they are based are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, operational and regulatory risks and uncertainties and are subject to material revision. Actual results may differ materially from our estimates and guidance, and we undertake no duty to update these statements.
