Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in our Annual Report on Form 10-K for the year ended December 31, 2015 filed with the SEC on March 15, 2016, and the historical unaudited condensed consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report.
Except as otherwise noted, all tabular amounts are in thousands, except per unit values.
Critical Accounting Policies
There have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K for the year ended December 31, 2015.
General
We are an independent energy company primarily engaged in the acquisition, exploration, exploitation, development and production of oil and gas in the United States. We focus on assets with a high working interest and low geologic risk as well as operational and infrastructure control. We seek strong full cycle rate of return and low risk exploitable upside using the Company's operating experience. We believe that we have a number of development opportunities on our properties and intend to expand upon our development activities with complementary exploration projects in our core areas of operation. Success in our development and exploration activities is critical in the maintenance and growth of our current production levels and associated reserves.
Factors Affecting Our Financial Results
Our financial results depend upon many factors which significantly affect our results of operations including the following:
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•
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commodity prices and the effectiveness of our hedging arrangements;
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•
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the level of total sales volumes of oil, gas and NGL;
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•
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the availability of and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;
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•
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the level of and interest rates on borrowings; and
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•
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the level and success of exploration and development activity
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Commodity Prices and Hedging Arrangements
.
The results of our operations are highly dependent upon the prices received for our oil and gas production. The prices we receive for our production are dependent upon spot market prices, differentials and the effectiveness of our derivative contracts, which we sometimes refer to as hedging arrangements. Substantially all of our sales of oil and gas are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and gas production are dependent upon numerous factors beyond our control. Significant declines in prices for oil and gas could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis.
Oil and gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world political environment, worldwide demand for, and supplies of oil, NGL and gas, the availability of other worldwide energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, we are unable to predict what changes may occur in oil, NGL, and gas prices in the future. The market price of oil, NGL and gas in 2015, and during the first nine months of 2016, have impacted the amount of cash generated from operating activities, and have in turn impacted our financial position.
During the nine months ended
September 30, 2016
, the NYMEX future price for oil averaged
$41.54
per Bbl as compared to
$50.98
per Bbl in 2015. During the nine months ended
September 30, 2016
, the NYMEX future spot price for gas averaged
$2.35
per MMBtu compared to
$2.76
per MMBtu in 2015. Prices closed on
September 30, 2016
at
$48.24
per Bbl of oil and
$2.91
per MMBtu of gas, compared to closing on
September 30, 2015
at
$45.09
per Bbl of oil and
$2.52
per MMBtu of gas. At November 7, 2016, prices closed at $44.89 per Bbl of oil and $2.82 per MMBtu of gas. If commodity prices remain at these levels or decline further, our revenue and cash flow from operations will also likely decline. In addition, lower commodity prices could also reduce the amount of oil and gas that we can produce economically. If oil and gas prices remain depressed or continue to decline, our revenues, profitability and cash flow from operations will also likely decrease which could cause us to alter our business plans, including reducing our drilling activities. Such declines have required, and in future periods could also require us to write down the carrying value of our oil and gas assets which would also cause a reduction in net income.
The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to:
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•
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basis differentials which are dependent on actual delivery location;
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•
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adjustments for BTU content;
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•
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quality of the hydrocarbons; and
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gathering, processing and transportation costs.
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The following table sets forth our average differentials for the nine months ended
September 30, 2016
and 2015:
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Oil - NYMEX
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Gas - NYMEX
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2016
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2015
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2016
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2015
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Average realized price (1)
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$
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34.13
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$
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42.94
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$
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1.10
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$
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2.16
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Average NYMEX price
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41.54
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50.98
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2.35
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2.76
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Differential
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$
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(7.41
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)
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$
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(8.04
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)
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$
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(1.25
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)
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$
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(0.60
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)
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_____________________________________
(1) Excludes the impact of derivative activities.
At
September 30, 2016
, our derivative contracts consisted of fixed price swaps. Under fixed price swaps, we receive a fixed price for our production and pay a variable market price to the contract counter-party.
Our derivative contracts equate to approximately 70% of the estimated oil production from our net proved developed producing reserves (based on our reserve estimates as of June 30, 2016) through December 31, 2016, 90% in 2017, 88% in 2018 and 81% for 2019. By removing a portion of price volatility on our future oil and gas production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations for those periods. However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow. We have in the past and will in the future sustain losses on our derivative contracts if market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain gains on our commodity derivative contracts. For the nine months ended
September 30, 2016
, we realized a loss of
$10.3 million
, consisting of a gain of
$3.2 million
on closed contracts and a loss of
$13.5 million
related to open contracts. For the nine months ended September 30, 2015, we realized a gain of
$13.1 million
consisting of a gain of
$6.9 million
on closed contracts and a gain of
$6.2 million
related to open contracts. We have not designated any of these derivative contracts as hedges as prescribed by applicable accounting rules.
The following table sets forth our derivative contracts at
September 30, 2016
:
Fixed Price Swaps:
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Oil - WTI
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Contract Periods
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Daily Volume (Bbl)
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Swap Price (per Bbl)
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2016 October - December
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2,500
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$
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43.25
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2017
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2,401
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$
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54.53
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|
Subsequent to
September 30, 2016
we entered into the following derivative contracts.
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Oil - WTI
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Contract Periods
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Daily Volume (Bbl)
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Swap Price (per Bbl)
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2019
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1,197
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$
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54.54
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At
September 30, 2016
, the aggregate fair market value of our commodity derivative contracts was a net liability of approximately
$2.3 million
.
Production Volumes.
Our proved reserves will decline as oil and gas is produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities. Based on the reserve information set forth in our reserve estimates as of December 31, 2015, we anticipate our proved developed producing reserves to decline 33%, 26% and 15% in 2017, 2018 and 2019, respectively. Thereafter our reserves are expected to decline an estimated 10% annually. These rates of decline are estimates and actual production declines could be materially higher. While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and property sales. Our ability to acquire or find additional reserves in the future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects.
We had capital expenditures during the nine months ended
September 30, 2016
of
$24.6 million
related to our exploration and development activities. We are authorized to make capital expenditures in 2016 of up to $40.0 million. Based on current service cost trends, we anticipate capital expenditures to be approximately $35.0 million in 2016. The 2016 capital expenditure budget is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil and gas, the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, the availability of sufficient capital resources, the results of our exploitation efforts, and our ability to obtain permits for drilling locations.
The following table presents historical net production volumes for the three and nine months ended
September 30, 2016
and 2015:
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Three Months Ended
September 30,
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Nine Months Ended
September 30,
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2016
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2015
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2016
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2015
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Total production (MBoe)
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548
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552
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1,531
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1,643
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Average daily production (Boepd)
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5,955
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|
6,004
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5,586
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|
6,020
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% Oil
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61
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%
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|
66
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%
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|
60
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%
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67
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%
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Availability of Capital
.
As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flow from operating activities, borrowings under our credit facility, cash on hand, and if appropriate opportunities are available, issuing debt or equity securities, selling assets or monetizing our derivative contracts, although we may not be able to complete any such transactions on terms acceptable to us, if at all. On May 25, 2016, we completed a stock offering of 28.8 million shares of common stock for net proceeds of approximately $27.2 million. The net proceeds from this stock issuance were used to repay borrowings under our credit facility. As of
September 30, 2016
our borrowing base was $130.0 million. Under the terms of the April 2016 Amendment, the borrowing base was automatically reduced to $120.0 million on October 1, 2016. The borrowing base was further reduced to $115.0 million on October 31, 2016 in connection with the Fall 2016 Redetermination.
Borrowings and Interest
.
At
September 30, 2016
, we had a total of
$90.0 million
outstanding under our credit facility and total indebtedness of
$95.0 million
(including the current portion). If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements. As a result, we would need to increase our cash flow from operations in order to fund the development of our drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices.
Exploration and Development Activity.
We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us for future growth. At December 31, 2015, we operated properties accounting for approximately 95% of our PV-10, giving us substantial control over the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations on our existing leaseholds, the successful development of which we believe could significantly increase our production and proved reserves. Over the five years ended December 31, 2015, we drilled or participated in 145 gross (55.8 net) wells of which 97% were productive.
Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration and development activities will result in increases in our proved reserves. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility may also decline. In addition, approximately 60% of our estimated proved reserves on a Boe basis (19% on a PV-10 basis) at December 31, 2015 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We may be unable to acquire or develop additional reserves or develop our existing undeveloped reserves, in which case our results of operations and financial condition could be adversely affected.
Operational Update
Williston Basin
At our North Fork prospect, in McKenzie County, North Dakota, the Stenehjem 10H, 12H and 14H wells targeting the Three Forks averaged 1,059 Boepd (786 barrels of oil per day, 1,642 Mcf of natural gas per day) over their first 30 days of production. The Stenehjem 11H, 13H and 15H wells targeting the Middle Bakken averaged 1,226 Boepd (915 barrels of oil per day, 1,864 Mcf of natural gas per day) over their first 30 days of production. We own a working interest of approximately 78% in Stenehjem 10H-15H.
T
he 30-day average rates represent the highest 30 days of production and do not include the impact of natural gas liquids and shrinkage at the processing plant and include flared gas.
Austin Chalk
At our Jourdanton prospect in Atascosa County, Texas, the Bulls Eye 101H is currently on production. Although the well has not achieved the anticipated initial production rate to date, it did achieve reasonable production rates and has shown a very stable production profile. The well continues to clean up having recovered approximately 40% of its load water and over 15,000 Boes to date. We will update the market with more specific numbers once volumes stabilize. We own a 100% working interest in the Bulls Eye 101H.
Permian
In Ward County, Texas, we successfully drilled the Caprito 99-101H to a total depth of 15,665 feet. The completion of the Caprito 99-101H has been delayed due to completion issues on a third party’s well, which has delayed the arrival of the frac fleet. We have been advised by the third party frac company that the rig up date for our planned 25 stage completion of the Caprito 99-101H is now November 9. We own a 100% working interest in the Caprito 99-101H.
2016 Outlook
Market prices for oil, gas and NGL are inherently volatile. Accordingly, we cannot predict with certainty the future prices for the commodities we produce and sell. Current market fundamentals indicate prices for oil, gas and NGL will continue to be depressed for the remainder of 2016. Although changes in OPEC production strategies, geopolitical risks or other factors could impact current forecasts, we anticipate weak commodity prices throughout 2016. Depressed prices for oil, gas and NGL will likely have a material adverse effect on our results of operations and liquidity. Our primary sources of liquidity are cash flow from operations, borrowings under our credit facility, sales of non-core assets and other capital transactions, when available. Cash flow from operations is sensitive to many variables, the most volatile of which is the price of the oil, gas and NGL we produce and sell. Our consolidated cash flow from operations increased in the first nine months of 2016 primarily as a result of the monetization of some of our derivative positions. Availability under our credit facility is currently subject to a borrowing base of $115.0 million based on the Fall 2016 Redetermination . The amount of
the borrowing base is calculated by the lenders based upon their valuation of our proved reserves securing the facility utilizing these reserve reports and their own internal decisions. The lenders under our credit facility can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our credit facility.
As a result of the sharp decline in commodity prices, we recorded an impairment to our proved properties of $128.6 million for the year ended December 31, 2015 and an additional impairment of
$67.6 million
for the first nine months of 2016. The amount of any additional impairment is contingent upon many factors such as the price of oil, gas and NGL for the remainder of 2016, increases or decreases in our reserve base, changes in estimated costs and expenses, and oil and gas property acquisitions, which could increase, decrease or eliminate the need for such impairments.
While we will continue to operate and develop our portfolio of assets, we are committed to protecting our balance sheet and managing our capital programs. For 2017, Abraxas anticipates drilling expenditures to approximate cash flow. As a result, we can significantly reduce our capital budget in response to lower commodity prices. We are also committed to reducing our general and administrative, or "(G&A)" and field-level operating costs commensurate with our reduced, but focused, activity level. Abraxas President and CEO took a voluntary salary reduction of 20% effective September 1, 2015, and effective February 1, 2016, the remaining named executive officers of Abraxas took a voluntary salary reduction of 20%.
Results of Operations
Selected Operating Data
. The following table sets forth operating data from continuing operations for the periods presented.
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Three Months Ended
September 30,
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Nine Months Ended
September 30,
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2016
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2015
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2016
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2015
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|
Operating revenue (1):
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Oil sales
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$
|
12,713
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|
$
|
14,414
|
|
|
$
|
31,380
|
|
|
$
|
47,240
|
|
|
Gas sales
|
|
1,014
|
|
|
1,345
|
|
|
2,444
|
|
|
4,844
|
|
|
NGL sales
|
|
245
|
|
|
316
|
|
|
693
|
|
|
1,574
|
|
|
Other
|
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4
|
|
|
2
|
|
|
31
|
|
|
24
|
|
|
Total operating revenues
|
|
$
|
13,976
|
|
|
$
|
16,077
|
|
|
$
|
34,548
|
|
|
$
|
53,682
|
|
|
Operating loss
|
|
$
|
(4,952
|
)
|
|
$
|
(63,438
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)
|
|
$
|
(76,993
|
)
|
|
$
|
(69,504
|
)
|
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Oil sales (MBbls)
|
|
334
|
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|
365
|
|
|
919
|
|
|
1,100
|
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|
Gas sales (MMcf)
|
|
765
|
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|
750
|
|
|
2,232
|
|
|
2,246
|
|
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NGL sales (MBbls)
|
|
86
|
|
|
62
|
|
|
239
|
|
|
169
|
|
|
Oil equivalents (MBoe)
|
|
548
|
|
|
552
|
|
|
1,531
|
|
|
1,643
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Average oil sales price (per Bbl)(1)
|
|
$
|
38.08
|
|
|
$
|
39.50
|
|
|
$
|
34.13
|
|
|
$
|
42.94
|
|
|
Average gas sales price (per Mcf)(1)
|
|
$
|
1.32
|
|
|
$
|
1.79
|
|
|
$
|
1.10
|
|
|
$
|
2.16
|
|
|
Average NGL sales price (per Bbl)
|
|
$
|
2.83
|
|
|
$
|
5.07
|
|
|
$
|
2.90
|
|
|
$
|
9.32
|
|
|
Average oil equivalent sales price (Boe) (1)
|
|
$
|
25.50
|
|
|
$
|
29.10
|
|
|
$
|
22.55
|
|
|
$
|
32.65
|
|
|
___________________
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(1)
|
Revenue and average sales prices are before the impact of hedging activities.
|
Comparison of Three Months Ended September 30, 2016 to Three Months Ended September 30, 2015
Operating Revenue
. During the three months ended
September 30, 2016
, operating revenue decreased to
$14.0 million
from
$16.1 million
for the same period of 2015. The decrease in revenue was primarily due to lower prices for all products as well as lower sales volumes for oil. Lower realized commodity prices had a negative impact on revenue of $1.0 million of which $0.5 million was attributable to oil. Lower oil sales volumes had a negative impact on revenue of approximately $1.2 million for the three months ended
September 30, 2016
.
Oil sales volumes decreased to
334
MBbl during the three months ended
September 30, 2016
from
365
MBbl for the same period of 2015. The decrease in oil sales volume was primarily due to natural field declines and property sales. We sold non-core assets effective June 1, 2016 which contributed 14.4 MBbl in the third quarter of 2015. Production decreases
were partially offset by new wells brought on line since the third quarter of 2015 which contributed 150 MBbl for the three months ended
September 30, 2016
. Gas sales volumes increased to
765
MMcf for the three months ended
September 30, 2016
from
750
MMcf for the same period of 2015. The increase in gas production was due to new wells brought on line since September 30, 2015 which contributed 184 MMcf for the three months ended
September 30, 2016
, which was partially offset by natural declines as well as pipeline constraints. NGL sales volumes increased to
86
MBbl for the three months ended
September 30, 2016
from
62
MBbl for the same period of 2015. The increase in NGL sales was primarily due to more gas production in the Rocky Mountain Region which has a higher NGL content. NGL sales were negatively impacted by plant and pipeline issues in North Dakota and West Texas.
Lease Operating Expenses (“LOE”)
.
LOE for the three months ended
September 30, 2016
decreased to
$4.6 million
from
$5.2 million
for the same period in 2015. Due to the decline in commodity prices, there has been a decrease in the cost of services. Additionally we have focused on lowering LOE and shutting in marginal wells, as well as sales of non-core properties. We have also significantly reduced our non-recurring projects. LOE per Boe for the three months ended
September 30, 2016
was
$8.40
compared to
$9.48
for the same period of 2015. The decrease per Boe was due to lower costs incurred for the three months ended
September 30, 2016
as compared to the same period of 2015.
Production and Ad Valorem Taxes.
Production and ad valorem taxes for the three months ended
September 30, 2016
decreased to
$1.2 million
from
$1.6 million
for the same period of 2015. The decrease was due to lower commodity prices and lower sales volumes. Production taxes for the three month ended
September 30, 2016
were 9% of total oil, gas and NGL sales compared to 10% for the same period of 2015.
General and Administrative (“G&A”) Expense.
G&A expenses, excluding stock-based compensation, for the three months ended
September 30, 2016
increased to
$2.0 million
from
$1.8 million
for the same period of 2015. The increase in G&A expense was primarily the result of less G&A expense being capitalized due to decrease drilling activities, which was offset by cost savings measures, including salary reductions. G&A expense per Boe, excluding stock-based compensation, was
$3.64
for the quarter ended
September 30, 2016
compared to
$3.29
for the same period of 2015. The increase per Boe was primarily due to higher costs and lower production.
Stock-Based Compensation.
Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. In addition to options, restricted shares of the Company’s common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the three months ended
September 30, 2016
and 2015, stock-based compensation was
$0.8 million
for each period.
Depreciation, Depletion and Amortization (“DD&A”) Expense.
DD&A expense for the three months ended
September 30, 2016
decreased to
$6.4 million
from
$10.2 million
for the same period of 2015. The decrease was primarily the result of a reduction in the full cost pool as a result of the proved property impairment in 2015 and the first nine months of 2016. DD&A expense per Boe for the three months ended
September 30, 2016
was
$11.63
compared to
$18.40
in 2015.
Ceiling Limitation Write-Down
.
We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity and reported earnings. As of
September 30, 2016
, our net capitalized costs of oil and gas properties exceeded the cost ceiling of our estimated proved reserves by approximately
$3.8 million
, resulting in the recognition of a proved property impairment of the same amount. As of
September 30, 2015
, our net capitalized costs of oil and gas properties exceeded the cost ceiling of our estimated proved reserves by approximately
$59.9 million
, resulting in the recognition of a proved property impairment of the same amount.
The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves. We cannot assure you that we will not experience additional write-downs in the future. If commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our oil and gas properties may be required.
Interest Expense.
Interest
expense for the three months ended
September 30, 2016
and 2015 was constant at
$1.0 million
. Although overall debt levels were lower for the three months ended
September 30, 2016
as compared to 2015, our interest rate was slightly higher for the three months ended
September 30, 2016
as compared to 2015.
Loss (Gain) on Derivative Contracts
.
Derivative gains or losses are determined by actual derivative settlements during the period and on the periodic mark to market valuation of derivative contracts in place. We have elected not to apply hedge accounting to our derivative contracts; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consisted of NYMEX-based fixed price swaps as of
September 30, 2016
, and NYMEX-based fixed price swaps and three-way collar contracts as of
September 30, 2015
. The estimated value of our commodity derivative contracts was a net liability of approximately
$2.3 million
as of
September 30, 2016
. When our derivative contract prices are higher than prevailing market prices, we incur gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the three months ended
September 30, 2016
, we recognized a gain on our commodity derivative contracts of
$2.4 million
, consisting of a loss on closed contracts of
$1.1 million
and a gain of
$3.5 million
relating to open contracts. For the three months ended
September 30, 2015
, we recognized a gain on our commodity derivative contracts of
$12.2 million
, consisting of a gain of
$1.7 million
on closed contracts and a gain of
$10.5 million
related to open contracts. We monetized a portion of our derivative contracts in March and April 2016. Cash flows from future settlements are expected to decrease as a result.
Income Tax Expense.
For the three months ended
September 30, 2016
and 2015 there was no income tax expense recognized as a result of NOL carryforwards and a net loss in the three months ended
September 30, 2016
and 2015.
Comparison of Nine Months Ended
September 30, 2016
to Nine Months Ended
September 30, 2015
Operating Revenue
.
During the nine months ended
September 30, 2016
, operating revenue decreased to $
34.5 million
from
$53.7 million
for the same period of 2015. The decrease in revenue was primarily due to lower prices for all products as well as lower sales volumes for oil and gas. Lower realized commodity prices had a negative impact on revenue of $13.2 million, of which $9.7 million was attributable to oil. Lower sales volumes for oil and gas had a negative impact on revenue of $6.2 million.
Oil sales volumes decreased to
919
MBbl during the nine months ended
September 30, 2016
from
1,100
MBbl for the same period of 2015. The decrease in oil sales volume was primarily due to natural field declines and sales of non-core properties. We sold non-core properties effective June 1, 2016 which contributed 43.8 MBbl during the first nine months of 2015. Production decreases were offset by new wells brought on line since the third quarter of 2015 which contributed 267 MBbl for the nine months ended
September 30, 2016
. Gas sales volumes decreased to
2,232
MMcf for the nine months ended
September 30, 2016
from
2,246
MMcf for the same period of 2015. The decrease in gas sales was primarily due to natural field declines. Production decreases were partially offset by new wells brought on line. New wells brought onto production contributed 364 MMcf for the nine months ended
September 30, 2016
. NGL sales volumes increased to
239
MBbl for the nine months ended
September 30, 2016
from
169
MBbl for the same period of 2015. The increase in NGL sales was primarily due to a higher percentage of our gas production from West Texas, North Dakota and the Eagle Ford that has a higher NGL content.
LOE
.
LOE
for the nine months ended
September 30, 2016
decreased to
$13.6
million from
$17.8 million
for the same period of 2015. Due to the decline in commodity prices, there has been a decrease in the cost of services. Additionally, we have focused on lowering LOE and shutting in marginal wells. We have also significantly reduced non-recurring workover projects. LOE per Boe for the nine months ended
September 30, 2016
was
$8.89
compared to
$10.83
for the same period of 2015. The decrease per Boe was due to lower service costs for the nine months ended
September 30, 2016
as compared to the same period of 2015.
Production and Ad Valorem Taxes
. Production and ad valorem taxes for the nine months ended
September 30, 2016
decreased to
$3.6 million
from
$5.3 million
for the same period of 2015. The decrease was primarily the result of lower commodity prices and lower sales volumes. Production taxes for the nine months ended September 30, 2016 and 2015 were 10% of total oil, gas and NGL sales.
G&A Expenses.
G&A expenses, excluding stock-based compensation, decreased to
$5.8 million
for the first nine months of 2016 from
$6.1 million
for the same period of 2015. The decrease in G&A expense was primarily related to cost saving measures, including reduced salaries. G&A expense per Boe, excluding stock-based compensation expense, was
$3.81
for the nine months ended
September 30, 2016
compared to
$3.71
for the same period of 2015. The increase per Boe was primarily due to the decrease in volumes produced offset by the lower costs in the first nine months of 2016 compared to the same period in 2015.
Stock-Based Compensation.
Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. In addition to options, restricted shares of the Company's common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the nine months ended
September 30, 2016
stock based compensation was
$2.4 million
as compared to
$3.1 million
for the same period of 2015. The decrease was primarily due to option grants in 2016 at a lower stock price as compared to 2015.
DD&A Expenses
. DD&A expense for the nine months ended
September 30, 2016
decreased to
$17.9 million
from
$31.0 million
for same period of 2015. The decrease was primarily the result of a reduction in the full cost pool as a result of impairments in 2015 and 2016. Our DD&A expense per Boe for the nine months ended
September 30, 2016
was
$11.72
compared to
$18.89
in 2015.
Ceiling Limitation Write-Down
.
We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity and reported earnings. As of
September 30, 2016
, our net capitalized costs of oil and gas properties exceeded the cost ceiling of our estimated proved reserves by approximately
$3.8 million
,
resulting in the recognition of a proved property impairment of the same amount. Total impairment for the nine months ended September 30, 2016 was
$67.6 million
, which includes $63.8 recognized in the first half of 2016. As of
September 30, 2015
, our net capitalized costs of oil and gas properties exceeded the cost ceiling of our estimated proved reserves by approximately
$59.9 million
, resulting in the recognition of a proved property impairment of the same amount.
The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves. We cannot assure you that we will not experience additional write-downs in the future. If commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our oil and gas properties may be required.
Interest Expense.
Interest
expense for the nine months ended
September 30, 2016
was
$3.3 million
as compared to
$2.8 million
for the same period of 2015. The increase in 2016 was due to higher interest rates during the nine months of 2016 as compared to the same period of 2015.
Loss (Gain) on Derivative Contracts
.
We account for derivative contract gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative contracts in place. Our derivative contract transactions do not qualify for hedge accounting; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. During the nine months ended
September 30, 2016
, our derivative contracts consisted of commodity swaps. The net estimated value of our commodity derivative contracts was a net liability of approximately
$2.3 million
as of
September 30, 2016
. When our derivative contract prices are higher than prevailing market prices, we incur realized and unrealized gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur realized and unrealized losses. For the nine months ended
September 30, 2016
, we recognized a loss on our commodity derivative contracts of
$10.3 million
, consisting of a gain on closed contracts of
$3.2 million
and a loss of
$13.5 million
relating to open contracts. For the nine months ended September 30, 2015, we recognized a gain on our commodity derivative contracts of
$13.1 million
, consisting of a gain of
$6.9 million
on closed contracts and a gain of
$6.2 million
related to open contracts. We monetized a portion of our derivative contracts in March and April 2016. Cash flows from future settlements are expected to decrease as a result.
Income Tax Expense.
For the nine months ended
September 30, 2016
and 2015 there was no income tax expense recognized as a result of NOL carryforwards and a net loss in the nine months ended
September 30, 2016
.
Liquidity and Capital Resources
General
. The oil and gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to service debt and to fund the following:
|
|
•
|
the development and exploration of existing properties, including drilling and completion costs of wells;
|
|
|
•
|
acquisition of interests in additional oil and gas properties; and
|
|
|
•
|
production and transportation facilities.
|
The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, will directly affect our ability to service our debt obligations and to grow the business through the development of existing properties and the acquisition of new properties.
Our principal sources of capital are cash flow from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, and if appropriate opportunities are available, selling of debt or equity securities, selling assets or monetizing derivative contracts, although we may not be able to complete any such transactions on terms acceptable to us, if at all. Based upon current oil, gas and NGL price expectations and our commodity derivatives positions, we anticipate that our cash on hand, cash flow from operations and available borrowing capacity under our revolving credit facility will provide us sufficient liquidity to fund our operations for the remainder of 2016 including our planned capital expenditures.
On September 20, 2016 we closed on the sale of our Portilla oil and gas properties as well as related surface for approximately $13.1 million. Proceeds from this sale were used to reduce amounts outstanding under our credit facility.
Capital Expenditures
. Capital expenditures for the nine months ended
September 30, 2016
and 2015 were
$24.6 million
and
$52.6 million
, respectively.
The table below sets forth the components of these capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
(In thousands)
|
Expenditure category:
|
|
|
|
|
|
Exploration/Development
|
|
$
|
24,549
|
|
|
$
|
51,939
|
|
|
Facilities and other
|
|
83
|
|
|
675
|
|
|
Total
|
|
$
|
24,632
|
|
|
$
|
52,614
|
|
|
During the nine months ended
September 30, 2016
and 2015 our expenditures were primarily for development of our existing properties. We are authorized to make capital expenditures in 2016 of up to $40.0 million. Based on current service cost trends, we anticipate capital expenditures to be approximately $35.0 million in 2016. The 2016 capital expenditure budget is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil and gas, the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, the availability of sufficient capital resources, the results of our exploitation efforts, and our ability to obtain permits for drilling locations.
Sources of Capital.
The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
(In thousands)
|
Net cash provided by operating activities
|
|
$
|
22,225
|
|
|
$
|
125
|
|
|
Net cash (used in) investing activities
|
|
(7,039
|
)
|
|
(52,476
|
)
|
|
Net cash (used in) provided by financing activities
|
|
(18,726
|
)
|
|
48,599
|
|
|
Total
|
|
$
|
(3,540
|
)
|
|
$
|
(3,752
|
)
|
|
Operating activities for the nine months ended
September 30, 2016
provided
$22.2 million
in cash compared to providing
$0.1 million
in the same period of 2015. Non-cash expense items, net changes in operating assets and liabilities and the monetization of hedges accounted for most of these funds. Investing activities used
$7.0 million
during the nine months ended
September 30, 2016
, capital expenditures of
$24.6 million
, and were offset by proceeds from sales of oil and gas properties of
$13.6 million
for the period. Investing activities for the nine months ended September 30, 2015 used
$52.5
million
. Funds used during the nine months ended
September 30, 2016
and 2015 were primarily for the development of our existing properties. Financing activities used
$18.7 million
for the nine months ended
September 30, 2016
compared to providing
$48.6 million
for the same period of 2015. Funds used during the nine months ended
September 30, 2016
were primarily payments on borrowings under our credit facility offset by proceeds from the equity offering in May 2016. Funds provided during the nine months ended September 30, 2015 were primarily proceeds from borrowings under our credit facility.
Future Capital Resources
. Our principal sources of capital going forward are cash flow from operating activities, borrowings under our credit facility, cash on hand, and if appropriate opportunities are available, issuing of debt or equity securities, selling assets or monetizing our derivative contracts, although we may not be able to complete any such transactions on terms acceptable to us, if at all.
Cash from operating activities is dependent upon commodity prices and production volumes. Depressed commodity prices have reduced, and further decreases in commodity prices from current levels could reduce our cash flows from operations. This could cause us to alter our business plans, including reducing our exploration and development plans. Unless we otherwise expand and develop reserves, our production volumes may decline as reserves are produced. In the future we may continue to sell producing properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful exploration and development activities, acquire additional producing properties or identify and develop additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase our production volumes; however, our drilling activities are subject to numerous risks, including availability of capital and the risk that no commercially productive oil and gas reservoirs will be found. If our proved reserves decline in the future, our production could also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility could also decline. The risk of not finding commercially productive reservoirs will be compounded by the fact that 60% of our total estimated proved reserves on a Boe basis (19% on a PV-10 basis) at December 31, 2015 were classified as undeveloped.
We have in the past, and may in the future, sell producing properties. We have also sold debt and equity securities in the past, and may sell additional debt and equity securities in the future when the opportunity presents itself.
Contractual Obligations.
We are committed to making cash payments in the future on the following types of agreements:
|
|
•
|
Operating leases for office facilities.
|
Below is a schedule of the future payments that we are obligated to make based on agreements in place as of
September 30, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due in twelve month periods ending:
|
Contractual Obligations
(In thousands)
|
|
Total
|
|
September 30, 2017
|
|
September 30, 2018-2019
|
|
September 30, 2020-2021
|
|
Thereafter
|
Long-term debt (1)
|
|
$
|
94,993
|
|
|
$
|
1,313
|
|
|
$
|
90,529
|
|
|
$
|
576
|
|
|
$
|
2,575
|
|
Interest on long-term debt (2)
|
|
5,661
|
|
|
2,899
|
|
|
2,336
|
|
|
248
|
|
|
178
|
|
Lease obligations (3)
|
|
76
|
|
|
43
|
|
|
33
|
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
100,730
|
|
|
$
|
4,255
|
|
|
$
|
92,898
|
|
|
$
|
824
|
|
|
$
|
2,753
|
|
___________________________
|
|
(1)
|
These amounts represent the balances outstanding under our credit facility, the rig loan agreement and the real estate lien note. These payments assume that we will not borrow additional funds.
|
|
|
(2)
|
Interest expense assumes the balances of long-term debt at the end of the period and current effective interest rates.
|
|
|
(3)
|
Lease on office space in Dickinson, North Dakota, which expires on October 31, 2018, office space in Lusk, Wyoming, which will expire on December 31, 2016 and office space in Denver, Colorado which will expire on December 31, 2017.
|
We maintain a reserve for costs associated with future site restoration related to the retirement of tangible long-lived assets. At
September 30, 2016
, our reserve for these obligations totaled
$8.6 million
for which no contractual commitments exist. For additional information relating to this obligation, see Note 1 of the Notes to Condensed Consolidated Financial Statements.
Off-Balance Sheet Arrangements.
At
September 30, 2016
we had no existing off-balance sheet arrangements, as defined under SEC regulations, that have, or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.
Contingencies.
From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At
September 30, 2016
, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.
Long-Term Indebtedness.
Long-term debt consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2016
|
|
December 31, 2015
|
|
|
(In thousands)
|
Credit facility
|
|
$
|
90,000
|
|
|
$
|
134,000
|
|
Rig loan agreement
|
|
1,065
|
|
|
2,620
|
|
Real estate lien note
|
|
3,928
|
|
|
4,112
|
|
|
|
94,993
|
|
|
140,732
|
|
Less current maturities
|
|
(1,313
|
)
|
|
(2,330
|
)
|
|
|
$
|
93,680
|
|
|
$
|
138,402
|
|
Credit Facility
We have a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility. As of
September 30, 2016
,
$90.0 million
was outstanding under the credit facility.
The credit facility has a maximum commitment of
$300.0 million
and availability is subject to a borrowing base. The borrowing base is determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves securing the facility utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we are able to request one redetermination during any six-month period between scheduled redeterminations. The borrowing base will be automatically reduced in connection with any sales of producing properties with a market value of 5% or more of our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing base can never exceed the $300.0 million maximum commitment amount.
At
September 30, 2016
, we had a borrowing base of
$130.0 million
, based on the April 2016 Amendment. In accordance with the terms of the April 2016 Amendment, the borrowing base was automatically reduced to
$120.0 million
effective October 1, 2016. The borrowing base was further reduced to
$115.0 million
on October 31, 2016 in connection with the Fall 2016 Redetermination.
Outstanding amounts under the credit facility bear interest (x) at any time an event of default exists, at
3%
per annum plus the amounts set forth below, (y) between April 1, 2016 and October 1, 2016 , 0.25% per annum plus the rates set forth below and (z) at all other times, at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus
0.5%
, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b)
0.75%
-
1.75%
, depending on the utilization of the borrowing base, or, if we elect, LIBOR plus, in each case,
1.75%
-
2.75%
depending on the utilization of the borrowing base. At
September 30, 2016
, the interest rate on the credit facility was approximately
3.02%
assuming LIBOR borrowings.
Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is
June 30, 2018
. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. We are permitted
to terminate the credit facility and are able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.
Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets, other than Raven Drilling. In connection with the April 2016 Amendment, we also agreed to grant our lenders a security interest in our headquarters building (in addition to the lien granted to the lender under our building loan described below) and two ranches we own, none of which had previously secured our obligations under the credit facility. One of the ranches was sold in September 2016 in connection with the sale of our Portilla oil and gas properties.
Under the credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are required to maintain a current ratio, as of the last day of each quarter of not less than
1.00
to 1.00 and an interest coverage ratio of not less than
2.50
to 1.00. We are also required as of the last day of each quarter to maintain a total debt to EBITDAX ratio of not more than
4.00
to 1.00. The current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20 and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20. The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is defined as the sum of consolidated net income plus interest expense, oil and gas exploration expenses, income, franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts plus expenses incurred in connection with the negotiation, execution, delivery and performance of the credit facility plus expenses incurred in connection with any acquisition permitted under the credit facility plus expenses incurred in connection with any offering of senior unsecured notes, subordinated debt or equity plus up to $1.0 million of extraordinary expenses in any 12-month period plus extraordinary losses minus all non-cash items of income which were included in determining consolidated net income (loss), including all non-cash items resulting from the application of ASC 815 and ASC 410-20. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with the office building, Raven Drilling’s rig loan and obligations with respect to surety bonds and derivative contracts
.
At
September 30, 2016
we were in compliance with all of our debt covenants. As of
September 30, 2016
, the interest coverage ratio was
9.65
to 1.00, the total debt to EBITDAX ratio was
2.37
to 1.00, and our current ratio was
1.73
to 1.00.
The credit facility contains a number of covenants that, among other things, restrict our ability to:
|
|
•
|
incur or guarantee additional indebtedness;
|
|
|
•
|
transfer or sell assets;
|
|
|
•
|
create liens on assets;
|
|
|
•
|
engage in transactions with affiliates other than on an “arm’s length” basis;
|
|
|
•
|
make any change in the principal nature of our business; and
|
|
|
•
|
permit a change of control.
|
The April 2016 Amendment also included certain additional covenants including:
|
|
•
|
100% of the net proceeds from any sale of any of our properties occurring between April 1, 2016 and October 1, 2016 must be used to repay amounts outstanding under the credit facility;
|
|
|
•
|
100% of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility;
|
|
|
•
|
if the sum of our cash on hand plus liquid investments exceeds $10.0 million, then the amount in excess of $10.0 million must be used to pay amounts outstanding under the credit facility; and
|
|
|
•
|
granting the lenders a security interest in at least 90% of the PV-10 of our proven reserves.
|
The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.
Rig Loan Agreement
On September 19, 2011 Raven Drilling entered into a rig loan agreement, secured by our Oilwell
2,000
HP diesel electric drilling rig (the “Collateral”). The principal amount of the note was
$7.0 million
and bears interest at
4.26%
. The note is payable in monthly interest and principal payments in the amount of
$179,695
. Subject to earlier prepayment provisions and events of default, the stated maturity date of the note is
February 14, 2017
. As of
September 30, 2016
and December 31, 2015,
$1.1 million
and
$2.6 million
, respectively, were outstanding under the rig loan agreement.
The Company has guaranteed Raven Drilling’s obligations under the rig loan agreement and associated note. Obligations under the rig loan agreement are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in the Collateral.
Real Estate Lien Note
We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. The note bears interest at a fixed rate of
4.25%
and is payable in monthly installments of $
34,354
. Beginning August 20, 2018, the interest rate will adjust to the bank's then current prime rate plus
1.00%
with a maximum rate of
7.25%
. The maturity date of the note is July 20, 2023. As of
September 30, 2016
and December 31, 2015,
$3.9 million
and
$4.1 million
, respectively, were outstanding on the note.
Hedging Activities
Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. We have entered into commodity swaps on approximately 79% of our estimated oil production from our net proved developed producing reserves (based on reserve estimates as of June 30, 2016) through December 31, 2016, 90% for 2017, 88% for 2018 and 81% for 2019.
By removing a portion of price volatility on our future oil and gas production, we believe that we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations. However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow on the portion of the production that has been hedged. We have sustained, and in the future will sustain, losses on our derivative contracts when market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain gains on our commodity derivative contracts.
If the disparity between our contract prices and market prices continues, we will sustain gains or losses on our derivative contracts. While gains and losses resulting from the periodic mark to market of our open contracts do not impact our cash flow from operations, gains and losses from settlements of our closed contracts do impact our cash flow from operations.
In addition, as our derivative contracts expire over time, we expect to enter into new derivative contracts at then-current market prices. If the prices at which we hedge future production are significantly lower than our existing derivative contracts, our future cash flow from operations would likely be materially lower.