ITEM 1.
BUSINESS
Overview
Synergy Resources Corporation ("we," "us," "Synergy," or the "Company") is a growth-oriented independent oil and gas company engaged in the acquisition, development, and production of oil and natural gas in the Denver-Julesburg Basin (“D-J Basin”), which we believe to be one of the premier, liquids-rich oil and natural gas resource plays in the United States. The D-J Basin generally extends from the Denver metropolitan area throughout northeast Colorado into Wyoming, Nebraska, and Kansas. It contains hydrocarbon-bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand, and D-Sand. The area has produced oil and natural gas for over fifty years and benefits from established infrastructure including midstream and refining capacity, long reserve life, and multiple service providers.
Our drilling and completion activities are focused in the Wattenberg Field, predominantly in Weld County, Colorado, an area that covers the western flank of the D-J Basin. Currently, we are focused on the horizontal development of the Codell and Niobrara formations, which are characterized by relatively high liquids content.
In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately 73% of our proved producing reserves, and anticipate operating substantially all of our future net drilling locations. Our current development plan anticipates that all of our future activities will be concentrated in the Wattenberg Field.
During the twelve months ended December 31, 2016, we continued to execute our plans for growth through development of our existing oil and gas properties and strategic acquisitions of leasehold and producing properties. As of December 31, 2016, we are the operator of 324 gross (288 net) producing wells, of which 110 gross (106 net) are Codell or Niobrara horizontal wells. The Company has also participated as a non-operator in 307 gross (65 net) producing wells. In addition, there were 49 gross (44 net) operated wells in various stages of drilling or completion as of December 31, 2016, which excludes 9 gross (9 net) wells for which we have only set surface casings.
For the twelve months ended December 31, 2016 and 2015, our average net daily production was 11,670 BOED and 9,548 BOED, respectively. By comparison, during the years ended August 31, 2015, 2014 and 2013, our average production rate was 8,750 BOED, 4,290 BOED, and 2,117 BOED, respectively. By the end of December 31, 2016, over 96% of our daily operated production was from horizontal wells.
Strategy
Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves, and cash flow through development, exploitation, exploration, and acquisitions of oil and gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures to lower risk development and exploitation activities. Key elements of our business strategy include the following:
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Concentrate on our existing core area in the D-J Basin, where we have significant operating experience. All of our current wells and our proved undeveloped acreage is located either in or adjacent to the Wattenberg Field. Focusing our operations in this area leverages our management, technical, and operational experience in the basin.
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Develop and exploit existing oil and gas properties. Our principal growth strategy has been to develop and exploit our properties to add reserves. In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. We believe horizontal drilling is the most efficient way to recover the potential hydrocarbons and consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential future wells. There is enough similarity between wells in the Wattenberg Field that the exploitation process is generally repeatable.
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Improve hydrocarbon recovery through increased well density. We utilize what we believe to be industry best practices in our effort to determine the optimal recovery area for each well. Early horizontal well development in the Wattenberg Field generally assumed optimal recoveries would be obtained utilizing between 12 and 16 wells per 640-acre section. As horizontal well development has matured, well density assumptions have generally increased beyond 16 wells per section depending on the specific area of the field being drilled.
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Complete selective acquisitions. We seek to acquire developed and undeveloped oil and gas properties, primarily in the Wattenberg Field. We generally seek acquisitions that will provide us with opportunities for reserve additions and
increased cash flow through production enhancement and additional development and exploratory prospect generation.
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Retain control over the operation of a substantial portion of our production. As operator of a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled. This allows us to modify our capital spending as our financial resources and underlying lease terms allow and market conditions permit.
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Maintain financial flexibility while focusing on operational cost control. We strive to be a cost-efficient operator and to maintain a relatively low utilization of debt, which enhances our financial flexibility. Our high degree of operational control, as well as our focus on operating efficiencies and short return on investment cycle times, is central to our operating strategy.
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Use the latest technology to maximize returns. Our development objective for individual well optimization is to drill and complete wells with lateral lengths of 7,000' to 10,000' as opposed to the 4,000' laterals that were initially drilled in the Wattenberg Field. Utilizing petrophysical and seismic data, a 3-D model is developed for each leasehold section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation-specific drilling and completion execution designs and coupled with localized production results to provide a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development program.
Competitive Strengths
We believe that we are positioned to successfully execute our business strategy because of the following competitive strengths:
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Core acreage position in the Wattenberg Field. Wells in our core properties in the Wattenberg Field generally exhibit high liquids content, and those properties are generally prospective for Niobrara A, B, and C bench and Codell development. We believe that these factors will lead to attractive EURs per acres of leasehold, per unit capital and operating costs, and rates of return. Increased well density within the Codell and Niobrara formations, as well as our acquisition efforts and organic leasing efforts within the core Wattenberg Field, have added to our multi-year drilling inventory.
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Financial flexibility. Our capital structure, along with our high degree of operational control, continues to provide us with significant financial flexibility. We have historically utilized very little debt in our capital structure. Our low debt level has enabled us to make capital decisions with limited restrictions imposed by debt covenants, lender oversight, and/or mandatory repayment schedules. Additionally, as the operator of substantially all of our anticipated future drilling locations per our December 31, 2016 reserve report, we control the timing and selection of drilling locations as well as completion schedules. This allows us to modify our capital spending program depending on financial resources, leasehold requirements, and market conditions.
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Management experience. Members of our key management team possess an average of over thirty years of experience in oil and gas exploration and production in multiple resource plays including the Wattenberg Field.
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Balanced oil and natural gas reserves and production. At December 31, 2016, approximately 73% of total gross revenues were oil and condensate, and 27% were natural gas. We believe that this balanced commodity mix will provide diversification of sources of cash flow.
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Cost-efficient and safe operator. We have continued to demonstrate our ability to drill wells in a cost-efficient and safe way and to successfully integrate acquired assets without incurring significant increases in overhead.
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High success rate. We have concentrated our drilling in areas that we perceive as relatively low risk and, as a result, have had a very high success rate in our drilling program throughout the Wattenberg Field.
Properties
As of December 31, 2016, our estimated net proved oil and natural gas reserves, as prepared by our independent reserve engineering firm Ryder Scott Company, L.P. ("Ryder Scott"), were 38.0 MMBbls of oil and condensate and 331.9 Bcf of natural gas. As of December 31, 2016, we had approximately 397,200 gross and 332,400 net acres under lease. We further delineate our acreage into specific areas, including the areas that we refer to as the Wattenberg Field (approximately 78,500 gross and 68,900 net acres) and the North East Extension Area (approximately 55,300 gross and 27,600 net acres). In addition, we hold approximately
183,600 gross (180,400 net) acres in southwest Nebraska, a conventional oil-prone prospect, and approximately 77,900 gross (54,200 net) acres in other areas of Colorado.
We currently operate over 73% of our proved producing reserves, and over 98% of our drilling and completion expenditures during the twelve months ended December 31, 2016 were focused on the Wattenberg Field. Substantially all of our drilling and completion expenditures for the 2017 calendar year are anticipated to be focused on the Wattenberg Field. A high degree of operational and capital control gives us both operational focus and development flexibility to maximize returns on our leasehold position.
Significant Business Developments
Acquisitions
In May 2016, the Company entered into an agreement ("GC Agreement") to purchase a total of approximately 72,000 gross (33,100 net) acres located in an area known as the Greeley-Crescent development area in Weld County Colorado, primarily in and around the city of Greeley, for $505 million ("GC Acquisition"). Estimated net daily production from the acquired properties was approximately 2,400 BOE at the time we entered into the agreement. On June 14, 2016, the Company closed on the portion of the assets comprised of the undeveloped lands and non-operated production. The effective date of this part of the transaction was April 1, 2016, and the purchase price was $486.4 million, comprised of $485.1 million in cash and the assumption of certain liabilities. The second closing will cover the operated producing properties and is expected to be completed in 2017. The Company has placed $18.2 million in escrow to be released upon the second closing. For the second closing, the effective date will be April 1, 2016 for the horizontal wells to be acquired and the first day of the calendar month in which the closing for such properties occurs for the vertical wells. The second closing is subject to certain closing conditions including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all.
During 2016, the Company completed various other acquisitions of undeveloped oil and natural gas leasehold interests in the D-J Basin for a total of $20.7 million in cash and the assumption of certain liabilities or receivables. These acquisitions were completed in an effort to increase our working interests and to extend the lateral lengths of our wells. See Note 3 to the consolidated financial statements included in this report for further discussion.
Divestitures
In April 2016, the Company agreed to divest approximately 3,700 net undeveloped acres primarily in Adams County, Colorado and 107 vertical wells primarily in Weld County, Colorado for total consideration of approximately $24.7 million in cash and the assumption by the buyers of $0.5 million in liabilities. The divested assets had associated production of approximately 200 BOED at the time of sale. The vertical well transaction closed in April 2016 and the undeveloped acreage transaction closed in June 2016.
In January 2017, we executed a purchase and sale agreement with a private party resulting in the divestiture of acreage outside of the Company's core development area. The transaction resulted in the Company divesting approximately 10,000 net undeveloped acres and approximately 700 BOED of associated production for $71 million. The transaction is expected to close in the first quarter of 2017.
Equity offerings
In January 2016, the Company closed on the sale of 16,100,000 shares of common stock pursuant to an underwriting agreement with Credit Suisse Securities (USA) LLC, acting severally on behalf of itself and the other underwriters. The price to the Company was $5.545 per share, and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $89.2 million. Proceeds were used to repay amounts borrowed under the revolving credit facility and for general corporate purposes, which included continuing to develop our acreage position in the Wattenberg Field and funding a portion of our 2016 capital expenditure program.
In April 2016, the Company closed on the sale of an additional 22,425,000 shares of common stock pursuant to an underwriting agreement with substantially the same underwriting group. The price to the Company was $7.3535 per share, and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $164.8 million. The proceeds of this offering were used for general corporate purposes, including to fund the GC Acquisition.
In May and June 2016, the Company closed on the sale of an additional 51,750,000 shares of common stock pursuant to an underwriting agreement with substantially the same underwriting group. The price to the Company was $5.597 per share, and
net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $289.4 million. The proceeds of this offering were used for general corporate purposes, including to fund the GC Acquisition.
Revolving Credit Facility
We continue to maintain a borrowing arrangement with our bank syndicate to provide us with liquidity, which could be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. As of December 31, 2016, this revolving credit facility (sometimes referred to as the "Revolver") provides for maximum borrowings of $500 million, subject to adjustments based upon a borrowing base calculation, which is redetermined semi-annually using updated reserve reports. The Revolver is collateralized by certain of our assets, including substantially all of our producing wells and developed oil and gas leases, and bears a variable interest rate on borrowings with the effective rate varying with utilization. The Revolver expires on December 15, 2019. See further discussion in Note 6 to our consolidated financial statements
In October 2016, the Revolver was amended in connection with the semi-annual redetermination of the borrowing base. The borrowing base was increased from $145 million to $160 million. Due to outstanding letters of credit, approximately $159.5 million of the borrowing base was available to use for future borrowings as of December 31, 2016.
The Revolver contains covenants that, among other things, restrict the payment of dividends and limit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved reserves as projected in the semi-annual reserve report.
The Revolver also requires the Company to maintain compliance with certain financial and liquidity ratio covenants. Under the requirements, the Company, on a quarterly basis, must not (a) at any time permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; or (b) as of the last day of any fiscal quarter permit its current ratio, as defined in the agreement, to be less than 1.0 to 1.0. As of December 31, 2016, the most recent compliance date, the Company was in compliance with these covenants and expects to remain in compliance throughout the next 12-month period.
Senior Notes
In June 2016, the Company issued $80 million aggregate principal amount of 9% Senior Notes ("Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Senior Notes accrues at 9% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each year, beginning on December 15, 2016. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 (the "Indenture") and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. The net proceeds from the sale of the Senior Notes were $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions. The net proceeds were used to fund the GC Acquisition. The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications.
Drilling and Completion Operations
During the periods presented below, we drilled or participated in the drilling of a number of wells that reached productive status in each respective period. During the twelve months ended December 31, 2016, we completed 24 wells in two separate spacing units. Due to proved well density thresholds, 6 of the wells are classified as exploratory and 18 of the wells are classified as development.
* Excludes 3 gross (0.42 net) productive wells which we participated in on a non-operated basis.
All of the oil wells in the table above are located in, or adjacent to, the Wattenberg Field of the D-J Basin. The three natural gas wells in the table above are located in Yuma County, Colorado. As of December 31, 2016, we were the operator of 49 gross (44 net) wells in progress, which excludes 9 gross (9 net) wells for which we have only set surface casings, that were not included in the above well counts.
Production Data
The following table shows our net production of oil and natural gas, average sales prices, and average production costs for the periods presented:
Major Customers
Historically, we sold our oil production to local refineries and, to a lesser degree, third-party marketers. During 2014, we secured contracts with additional oil purchasers who transport oil via pipelines. Under the contracts, we have delivery commitments covering a portion of our anticipated future production over the next four to five years. Our natural gas is sold under contracts with two midstream gas gathering and processing companies. We believe that both gas processing and oil takeaway capacity are sufficient to meet our anticipated production growth. See further discussion in Note 16 to our consolidated financial statements.
Oil and Gas Properties, Wells, Operations, and Acreage
We believe that the title to our oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following:
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royalties and other burdens and obligations, expressed or implied, under oil and gas leases;
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overriding royalties and other burdens created by us or our predecessors in title;
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a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farm-out agreements, production sales contracts, and other agreements that may affect the properties or title thereto;
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back-ins and reversionary interests existing as a result of pooling under state orders;
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liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors, and contractual liens under operating agreements;
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pooling, unitization and communitization agreements, declarations, and orders; and
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easements, restrictions, rights-of-way, and other matters that commonly affect property.
To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are customary in the industry for properties of the kind that we own.
The following table shows, as of December 31, 2016, by state, our producing wells, developed acreage, and undeveloped acreage:
1 Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of oil and natural gas regardless of whether the leasehold interest is classified as containing proved undeveloped reserves.
The following table shows, as of December 31, 2016, the status of our gross acreage:
Leases that are held by production generally remain in force so long as oil or natural gas is produced from the well on
the particular lease. Leased acres which are not held by production may require annual rental payments to maintain the lease until the expiration of the lease or the time oil or natural gas is produced from one or more wells drilled on the leased acreage. At the time oil or natural gas is produced from wells drilled on the leased acreage, the lease is generally considered to be held by production.
The following table shows the calendar years during which our leases not currently held by production will expire unless a productive oil or natural gas well is drilled on the lease or the lease is renewed.
The overriding royalty interests that we own are not material to our business.
Oil and Natural Gas Reserves
Our estimated proved reserve quantities increased by 41% from December 31, 2015 to December 31, 2016. At December 31, 2016, we had estimated proved reserves of 38.0 million barrels of oil and 331.9 billion cubic feet of gas. The estimated standardized measure of future net cash flow from our reserves at December 31, 2016 was $434.3 million and the
estimated PV-10 value of our reserves at that date was $476.3 million. PV-10 is a non-GAAP measure that reflects the present value, discounted at 10%, of estimated future net revenues from our proved reserves. We present a reconciliation of PV-10 value to the standardized measure of discounted future net cash flows in Item 7 under "Non-GAAP Financial Measures." The PV-10 value as of December 31, 2016 increased compared to December 31, 2015 by $38.2 million. The increase in estimated proved reserve quantities and PV-10 value is primarily due to better drilling efficiencies leading to an increase in the number of wells drilled per year and the GC Acquisition, which created spacing units with higher interests and the opportunity to drill longer laterals.
Ryder Scott prepared the estimates of our proved reserves, future production, and income attributable to our leasehold interests as of December 31, 2016. Ryder Scott is an independent petroleum engineering firm that has been providing petroleum consulting services worldwide for over seventy years. The estimates of proved reserves, future production, and income attributable to certain leasehold and royalty interests are based on technical analyses conducted by teams of geoscientists and engineers employed at Ryder Scott. The office of Ryder Scott that prepared our reserves estimates is registered in the State of Texas (License #F-1580). Ryder Scott prepared our reserve estimate based upon a review of property interests being appraised, historical production, lease operating expenses, price differentials, authorizations for expenditure, and geological and geophysical data.
The report of Ryder Scott dated January 20, 2017, which contains further discussions of the reserve estimates and evaluations prepared by Ryder Scott, as well as the qualifications of Ryder Scott’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this Annual Report on Form 10-K.
Our reserves technical team, which consists of our Reservoir Engineering Manager, VP of Exploration, COO - Operations, and COO - Development, oversaw the preparation of the reserve estimates by Ryder Scott to ensure accuracy and completeness of the data prior to and after submission. Our technical team has an average of over thirty years of experience in oil and gas exploration and development.
Our proved reserves include only those amounts which we reasonably expect to recover in the future from known oil and natural gas reservoirs under existing economic and operating conditions, at current prices and costs, under existing regulatory practices, and with existing technology. Accordingly, any changes in prices, operating and development costs, regulations, technology, or other factors could significantly increase or decrease estimates of proved reserves.
Estimates of volumes of proved reserves at year end are presented in barrels for oil and Mcf for natural gas at the official temperature and pressure bases of the areas in which the natural gas reserves are located.
The proved reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include decline curve analysis, which incorporate extrapolations of historical production and pressure data
available through December 31, 2016 in those cases where this data was considered to be definitive. The data used in this analysis was obtained from public sources and was considered sufficient for calculating producing reserves. The undeveloped reserves were estimated by the analogy method. The analogy method uses pertinent well data obtained from public sources that was available through December 31, 2016.
Below are estimates of our net proved reserves at December 31, 2016, all of which are located in Colorado:
The following tabulations present the PV-10 value of our estimated reserves as of December 31, 2016, December 31, 2015, August 31, 2015, and August 31, 2014 (in thousands):
The prices for the oil and natural gas reserves as of December 31, 2016 are based on the twelve-month arithmetic average for the first of month prices from January 1, 2016 through December 31, 2016. The following table presents the prices used to prepare the reserve estimates, based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials:
During the twelve months ended December 31, 2016, the combined effect of our drilling, acquisition, and participation activities partially offset by declining commodity prices generated an increase in projected future cash inflow from proved reserves of $470.1 million and an increase in future pre-tax net cash flow of $44.0 million from December 31, 2015 to December 31, 2016. During the same period, our PV-10 from proved reserves increased by $38.2 million. During the twelve months ended December 31, 2016, we incurred capital expenditures of approximately $283.3 million related to the acquisition and development of proved reserves.
Our drilling, acquisition, and participation activities during the four months ended December 31, 2015 and changes in commodity prices resulted in a decrease in projected future cash inflow from proved reserves of $336.0 million from August 31, 2015. Future pre-tax net cash flow decreased $25.2 million from August 31, 2015 to December 31, 2015. During that same period, our PV-10 from proved reserves decreased by $0.1 million. During the four months ended December 31, 2015, we incurred capital expenditures of approximately $92.5 million related to the acquisition and development of proved reserves.
Our drilling, acquisition, and participation activities, partially offset by declining commodity prices, during the year ended August 31, 2015 generated an increase in projected future cash inflow from proved reserves of $206.6 million compared to August 31, 2014. However, future pre-tax net cash flow decreased $149.6 million from August 31, 2014 to August 31, 2015 as per-unit costs did not decline commensurate with per-unit future cash inflow. During that same period, our PV-10 from proved reserves decreased by $95.4 million. During the year ended August 31, 2015, we incurred capital expenditures of approximately $203.2 million related to the acquisition and development of proved reserves.
Our drilling, acquisition, and participation activities during the year ended August 31, 2014 and changes in commodity prices resulted in increases in projected future cash inflow from proved reserves of $1.1 billion and future pre-tax net cash flow of $538.1 million from August 31, 2013. During that same period, our PV-10 from proved reserves increased by $297.6 million. During the year ended August 31, 2014, we incurred capital expenditures of approximately $185.1 million related to the acquisition and development of proved reserves.
In general, the volume of production from our oil and gas properties declines as reserves are depleted. Unless we acquire additional properties containing proved reserves, conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced. Accordingly, volumes generated from our future activities are highly dependent upon our success in acquiring or finding additional reserves, and the costs incurred in doing so.
At December 31, 2016, our proved undeveloped reserves were 75,489 MBOE. During 2016, the GC Acquisition, along with other minor acquisitions, led to an increase of 50,530 MBOE in proved undeveloped reserves. These acquisitions allowed for creating spacing units with higher working interests, opportunities to drill longer laterals, and increased focus on our development program in the core Wattenberg area. This increase was partially offset by a decrease of 12,144 MBOE as a result of the removal of certain legacy PUD locations as they are now expected to be developed beyond the three-year drilling plan. In addition to the 806 MBOE of prior year proved undeveloped reserves converted to proved developed reserves, we developed 3,217 MBOE of acquired proved undeveloped reserves during the year, and we drilled 5.4 net exploratory wells. Further, due to a better commodity market environment, our increase in expected drilling activity positively affected our proved undeveloped reserves. While our 2015 reserves estimate assumed no rig initially then an increase to two rigs during the first year, our 2016 reserves estimate now assumes two rigs working continually throughout the three-year plan period. In addition to the undeveloped locations added as a result of recent drilling and acquisitions, we limited our undeveloped locations related to horizontal wells to be drilled within this three-year horizon due to the current uncertainty in the oil and gas environment.
During the year end December 31, 2016, we converted 806 MBOE, or 2%, of our proved undeveloped reserves as of December 31, 2015 into proved developed reserves, requiring $9.4 million of drilling and completion capital expenditures. Due to the timing of our drilling operations and the use of multi-well pads, we ended the year with 3 fully drilled pads, comprised of 30 gross (27.8 net) wells, that were awaiting completion, of which 18 gross (16.4 net) were classified as proved undeveloped locations, representing 19% of proved undeveloped reserves as of December 31, 2015 and 12% of proved undeveloped reserves as of December 31, 2016. All 30 of these wells are being completed in the first half of 2017. All proved undeveloped reserves as of December 31, 2016 are expected to be converted to proved producing within three years, and within five years of their initial booking. Based on our current drilling plans for the next three years, we expect to allocate more funds to developmental drilling in areas of established production where ongoing and planned infrastructure buildout continues. None of our proved undeveloped reserves as of December 31, 2016 have been in this category for more than five years.
At December 31, 2015, our proved undeveloped reserves were 48,289 MBOE. We drilled 9 net exploratory wells and 4
net development wells during the four months ended December 31, 2015. This generated proved developed reserves from those exploratory wells as well as new proved undeveloped reserves due to direct offset locations. As a result, we recognized an increase in proved undeveloped reserves from extensions of 17,161 MBOE. The 4 net development wells converted 1,869 MBOE during the four months ended December 31, 2015, or 4%, of our proved undeveloped reserves as of August 31, 2015 into proved developed reserves, requiring $17.7 million of drilling and completion capital expenditures.
At August 31, 2015, our proved undeveloped reserves were 41,621 MBOE. We drilled 40 net exploratory wells and one net development well during the year ended August 31, 2015. This generated proved developed reserves from those exploratory wells, as well as new proved undeveloped reserves due to direct offset locations. In addition, our reserve estimates reflect the positive impact of additional offset operator activities within the Wattenberg Field. As a result, we recognized an increase in proved undeveloped reserves from extensions of 17,633 MBOE. The one net development well converted 414 MBOE during the year ended August 31, 2015, or 2%, of our proved undeveloped reserves as of August 31, 2014 into proved developed reserves, requiring $5.0 million of drilling and completion capital expenditures.
At August 31, 2014, our proved undeveloped reserves were 19,211 MBOE. During the year ended August 31, 2014, 587 MBOE or 12% of our proved undeveloped reserves as of August 31, 2013 were converted into proved developed reserves, requiring $14.9 million of drilling and completion capital expenditures. Executing our capital program during the year ended August 31, 2014 resulted in the addition of 13,436 MBOE in proved undeveloped reserves.
Delivery Commitments
See "Volume Commitments" in Note 16 to our consolidated financial statements included elsewhere in this report.
Competition and Marketing
We are faced with strong competition from many other companies and individuals engaged in the oil and gas business, many of which are very large, well-established energy companies with substantial capabilities and established earnings records. We may be at a competitive disadvantage in acquiring oil and gas prospects since we must compete with these individuals and companies, many of which have greater financial resources and larger technical staffs. It is nearly impossible to estimate the number of competitors; however, it is known that there are a large number of companies and individuals in the oil and gas business.
Exploration for and production of oil and natural gas are affected by the availability of pipe, casing and other tubular goods, and certain other oil field equipment including drilling rigs and tools. We depend upon independent contractors to furnish rigs, pressure pumping equipment, and tools to drill and complete our wells. Higher prices for oil and natural gas may result in competition among operators for drilling and completion equipment, tubular goods, and drilling and completion crews, which may affect our ability expeditiously to drill, complete, recomplete, and work over wells.
The market for oil and natural gas is dependent upon a number of factors beyond our control, which at times cannot be accurately predicted. These factors include the proximity of wells to, and the capacity of, oil and natural gas pipelines, the extent of competitive domestic production and imports of oil and gas, the availability of other sources of energy, fluctuations in seasonal supply and demand, and governmental regulation. In addition, there is always the possibility that new legislation may be enacted that would impose price controls or additional excise taxes upon oil, natural gas, or both. Oversupplies of oil and natural gas can be expected to occur from time to time and may result in the producing wells being shut-in. Imports of oil and natural gas may adversely affect the market for domestic oil and natural gas.
The market price for oil is significantly affected by policies adopted by the member nations of the Organization of the Petroleum Exporting Countries or OPEC. Members of OPEC establish production quotas among themselves for petroleum products from time to time with the intent of influencing the global supply of oil and consequently price levels. We are unable to predict the effect, if any, that OPEC, its members, or other countries will have on the amount of, or the prices received for, oil and natural gas.
Natural gas prices are now largely influenced by competition. Competitors in this market include producers, natural gas pipelines and their affiliated marketing companies, independent marketers, and providers of alternate energy supplies, such as coal. Changes in government regulations relating to the production, transportation, and marketing of natural gas have also resulted in significant changes in the historical marketing patterns of the industry.
General
Our offices are located at 1625 Broadway Suite 300, Denver, CO 80202. Our office telephone number is (720) 616-4300, and our fax number is (720) 616-4301. Subsequent to February 24, 2017, our offices will be located at 1675 Broadway Suite 2600, Denver, CO 80202.
We intend to propose that our shareholders approve a change in our legal name to “SRC Energy Inc.” at the 2017 annual meeting. Pending the shareholder vote on the proposal, we intend to use the new name and logo on a “doing business as” basis beginning on or about March 6, 2017. In addition, commencing on that date, we expect that our common stock will trade under the symbol “SRCI,” and our domain name will become SRCenergy.com.
Our Greeley offices includes field offices and an equipment yard.
As of December 31, 2016, we had 96 full-time employees.
Available Information
We make available on our website, www.syrginfo.com, under “Investor Relations, SEC Filings,” free of charge, our annual and transition reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file or furnish them to the U.S. Securities and Exchange Commission (“SEC”). You may also read or copy any document we file at the SEC's public reference room in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington D.C. 20549, or may obtain copies of such documents at the SEC's website at www.sec.gov. Please call the SEC at (800) SEC-0330 for further information on the public reference room.
Government Regulation
Our operations are subject to various federal, state, and local laws and regulations that change from time to time. Many of these regulations are intended to prevent pollution and protect environmental quality, including regulations related to permit requirements for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling, completing and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process, groundwater testing, air emissions, noise, lighting and traffic abatement, and the plugging and abandonment of wells. Other regulations are intended to prevent the waste of oil and natural gas and to protect the rights among owners in a common reservoir. These include regulation of the size of drilling and spacing units or proration units, the number or density of wells that may be drilled in an area, the unitization or pooling of oil and natural gas wells, and regulations that generally prohibit the venting or flaring of natural gas and that impose requirements regarding the ratability or fair apportionment of production from fields and individual wells. In addition, our operations are subject to regulations governing the pipeline gathering and transportation of oil and natural gas as well as various federal, state, and local tax laws and regulations.
Failure to comply with applicable laws and regulations can result in substantial penalties. Our competitors in the oil and gas industry are generally subject to regulatory requirements and restrictions similar to those that affect our operations. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe that we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance.
Regulation of production
Federal, state, and local agencies have promulgated extensive rules and regulations applicable to our oil and gas exploration, production, and related operations. Most states require drilling permits, drilling and operating bonds, the filing of various reports, and the satisfaction of other requirements relating to the exploration and production of oil and natural gas. Many states also have statutes or regulations addressing conservation matters including provisions governing the size of drilling and spacing units or proration units, the density of wells, and the unitization or pooling of oil and gas properties. The number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. In addition, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states like Colorado allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on the voluntary pooling of lands and leases. In areas with voluntary pooling, it may be more difficult to develop a project if the operator owns less than 100% of the leasehold, or one or more of our leases does not provide the necessary pooling authority. Further, the statutes and regulations of some states limit the rate at which oil and natural gas is produced from properties, prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. This may limit the amount of oil and natural gas that we can produce from our wells and may limit the number of wells or locations at which we can drill. The federal and state regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are amended or reinterpreted frequently, we are unable to predict the future cost or impact of complying with these laws.
The Colorado Oil and Gas Conservation Commission (“COGCC”) is the primary regulator of exploration and production of oil and gas resources in the principal area in which we operate. The COGCC regulates oil and gas operators through rules, policies, written guidance, orders, permits, and inspections. Among other things, the COGCC enforces specifications regarding drilling, development, production, abandonment, enhanced recovery, safety, aesthetics, noise, waste, flowlines, and wildlife. In recent years, the COGCC has amended its existing regulatory requirements and adopted new requirements with increased frequency. For example, in August 2013, the COGCC implemented new setback rules for oil and natural gas wells and production facilities near occupied buildings. The COGCC increased its setback distance to a uniform 500 feet statewide setback from occupied buildings and imposed new notice, meeting, and mitigation requirements for nearby homes and communities. In January 2013, the COGCC approved new rules that require operators to sample groundwater for hydrocarbons and other indicator compounds both before and after drilling. In December 2013, the COGCC issued new and more restrictive rules regarding spill reporting and remediation. In December 2014, the COGCC issued amendments clarifying and modifying a number of existing rules, including those governing drilling, plugging, mechanical integrity testing, blow out prevention, and waste management. In January 2015, the COGCC amended its enforcement and penalty rules to increase the maximum penalty for regulatory violations. In March 2015, the COGCC adopted new requirements for operations within floodplains. In January 2016, the COGCC approved new rules that require local government consultation and certain best management practices for large-scale oil and natural gas facilities in certain urban mitigation areas. The new rules also require operator registration and/or notifications to local governments with respect to future oil and natural gas drilling and production facility locations.
Regulation of sales and transportation of natural gas
Historically, the transportation and sales for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978, and the Federal Energy Regulatory Commission (“FERC”) regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated the price for all “first sales” of natural gas. Thus, all of our sales of natural gas may be made at market prices, subject to applicable contract provisions. Sales of natural gas are affected by the availability, terms, and cost of pipeline transportation. Since 1985, the FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. We cannot predict what further action the FERC will take on these matters. Some of the FERC's more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers, and marketers with which we compete.
Our natural gas sales are generally made at the prevailing market price at the time of sale. Therefore, even though we sell significant volumes to major purchasers, we believe that other purchasers would be willing to buy our natural gas at comparable market prices.
In August 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. The 2005 EPA directs the FERC, Bureau of Ocean Energy Management (“BOEM”), and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA amends the NGA to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. FERC rules implementing this provision make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme, or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases, or transportation subject to FERC jurisdiction. It, therefore, reflects a significant expansion of the FERC's enforcement authority. To date, we do not believe that we have been, nor do we anticipate that we will be, affected any differently than other producers of natural gas.
In 2007, the FERC issued a final rule on annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, and natural gas marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. The monitoring and reporting required by these rules have increased our administrative costs. To date, we do not believe that we have been, nor do we anticipate that we will be, affected any differently than other producers of natural gas.
Regulation of sales and transportation of oil
Our sales of oil are affected by the availability, terms, and cost of transportation. Interstate transportation of oil by pipeline is regulated by the FERC pursuant to the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport oil and refined products (collectively referred to as “petroleum pipelines”) be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with the FERC.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective, interstate and intrastate rates are equally applicable to all comparable shippers, we do not believe that the regulation of oil transportation rates will affect our operations in any way that is materially different than those of our competitors who are similarly situated.
In May 2015, the U.S. Department of Transportation issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of oil, including sampling, testing, and certification
requirements. In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas.
Regulation of derivatives and reporting of government payments
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was passed by Congress and signed into law in July 2010. The Dodd-Frank Act is designed to provide, among other things, a comprehensive framework for the regulation of the over-the-counter derivatives market with the intent to provide greater transparency and reduction of risk between counterparties. The Dodd-Frank Act subjects certain derivative market participants to a variety of capital, margin, and other requirements and requires many derivative transactions to be cleared on exchanges. The Dodd-Frank Act provides for a potential exemption from certain of these requirements for commercial end-users.
Environmental Regulations
As with the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state, and local laws and regulations designed to protect and preserve natural resources and the environment. Long-term and recent trends in environmental legislation and regulation are generally toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling, and other activities on certain lands lying within wilderness and other protected areas; mandate requirements and standards for operations; impose substantial liabilities and remedial obligations for pollution; and require the reclamation of certain lands.
The permits required for many of our operations are subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions, or both. In March 2015, the COGCC implemented regulatory and statutory amendments that significantly increase the potential penalties for violating the Colorado Oil and Gas Conservation Act or its implementing regulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate the $10,000 maximum penalty for violations without significant consequences; require the COGCC to assess a penalty for each day of violation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations. Following the adoption of this new penalty scheme, Colorado operators have experienced increased penalties for violations within COGCC’s jurisdiction. In the opinion of our management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in their interpretation could have a significant impact on us as well as the oil and gas industry in general.
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict and joint and several liability on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. Persons responsible for the release or threatened release of hazardous substances under CERCLA may be subject to liability for the costs of cleaning up those substances and for damages to natural resources. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations impose clean-up liability relating to petroleum and petroleum-related products. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although RCRA classifies certain oil field wastes as non-hazardous "solid wastes,” such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements. In May 2016, certain environmental groups filed suit against the Environmental Protection Agency (“EPA") in federal court for failing to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, asserting that the agency has not reviewed its RCRA Subtitle D regulations since July 1988. A proposed consent decree filed in December 2016 between EPA and the environmental groups commits EPA to decide whether to revise its RCRA Subtitle D criteria regulations and state plan guidelines for the oil and natural gas sector by March 2019.
Certain of our operations are subject to the federal Clean Air Act (“CAA”) and similar state and local requirements. The CAA may require certain pollution control requirements with respect to air emissions from our operations. The EPA and states continue to develop regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air-emission-related issues. Greenhouse gas recordkeeping and reporting requirements under the CAA took effect in 2011 and impose increased administrative and control costs. Federal New Source Performance Standards regarding oil and gas operations (“NSPS OOOO”) took effect in 2012, with more subsequent amendments, all of which have likewise added
administrative and operational costs. In June 2016, EPA finalized new regulations under the CAA to reduce methane emissions from new and modified sources in the oil and natural gas sector. These new regulations impose, among other things, new requirements for leak detection and repair, control requirements at oil well completions, and additional control requirements for gathering, boosting, and compressor stations. Concurrent with the proposed methane rules, the EPA also finalized a new rule regarding source determinations and permitting requirements for the onshore oil and gas industry under the CAA. Colorado adopted new regulations to meet the requirements of NSPS OOOO and promulgated significant new rules in February 2014 relating specifically to oil and natural gas operations that are more stringent than NSPS OOOO and directly regulate methane emissions from affected facilities.
In October 2015, the EPA lowered the national ambient air quality standard (“NAAQS”) for ozone under the CAA from 75 parts per billion to 70 parts per billion. Any resulting expansion of the ozone nonattainment areas in Colorado could cause oil and natural gas operations in such areas to become subject to more stringent emissions controls, emission offset requirements, and increased permitting delays and costs. In addition, the ozone nonattainment status for the Denver Metro North Front Range Ozone 8-Hour Non-Attainment area was bumped up by the EPA from “marginal” to “moderate” as a result of the area failing to attain the 2008 ozone NAAQS by the applicable attainment date of July 20, 2015. In 2016, the state of Colorado undertook a rulemaking to address the new “moderate” status, culminating in, among others, the incorporation of two existing state-only requirements for oil and natural gas operations into the federally-enforceable State Implementation Plan ("SIP"). During the fall of 2016, EPA also issued final Control Techniques Guidelines ("CTGs") for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Metro North Front Range Ozone 8-hour Non-Attainment area. In 2017, as part of the federal CTG process for oil and natural gas, Colorado will begin a stakeholder and rulemaking effort to compare the CTGs to existing Colorado requirements to ensure they meet applicable federal requirements. This process could result in new or more stringent air quality control requirements applicable to our operations. On March 10, 2016, EPA announced its intention to initiate a formal process under CAA § 111(d) to require companies operating existing oil and gas sources to provide information to assist EPA in developing comprehensive regulations to reduce methane emissions. Related to this effort, EPA sent out Information Collection Requests ("ICRs") in late 2016 to operators to gather information on existing sources of methane emissions, technologies to reduce those emissions, and the costs of those technologies in the production, gathering, processing, and transmission and storage segments of the oil and natural gas sector.
The federal Clean Water Act (“CWA”) and analogous state laws impose requirements regarding the discharge of pollutants into waters of the U.S. and the state, including spills and leaks of hydrocarbons and produced water. The CWA also requires approval for the construction of facilities in wetlands and other waters of the U.S., and it imposes requirements on storm water run-off. In June 2016, the EPA finalized new CWA pretreatment standards that would prevent onshore unconventional oil and natural gas wells from discharging wastewater pollutants to public treatment facilities. In June 2015, the EPA and the U.S. Army Corps of Engineers adopted a new regulatory definition of “waters of the U.S.,” which governs which waters and wetlands are subject to the CWA. This final rule has been stayed pending the resolution of ongoing litigation. Depending upon if and how the new definition is implemented, it could significantly expand the jurisdictional reach of the CWA in many states, including Colorado.
The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Some of our operations may be located in areas that are or may be designated as habitats for threatened or endangered species. In such areas, we may be prohibited from conducting operations at certain locations or during certain periods, and we may be required to develop plans for avoiding potential adverse effects. In addition, certain species are subject to varying degrees of protection under state laws.
Federal laws including the CWA require certain owners or operators of facilities that store or otherwise handle oil and produced water to prepare and implement spill prevention, control, countermeasure and response plans addressing the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) subjects owners and operators of facilities to strict and joint and several liability for all containment and cleanup costs and certain other damages arising from oil spills, including the government’s response costs. Spills subject to the OPA may result in varying civil and criminal penalties and liabilities.
In 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic conditions. Based on these findings, the EPA adopted regulations under the CAA that, among other things, established Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already major sources of emissions of regulated pollutants. In a subsequent ruling, the U.S. Supreme Court upheld a portion of EPA’s GHG stationary source program, but invalidated a portion of it. The Court held that stationary sources already subject to the PSD or Title V program for non-GHG criteria pollutants remained subject to GHG best available control technology ("BACT") requirements, but ruled that sources subject to the PSD or Title V program only for GHGs could not be forced to comply with GHG BACT requirements. Upon remand, the D.C. Circuit issued an amended judgment, which, among other things, vacated the PSD and Title V regulations
under review in that case to the extent they require a stationary source to obtain a PSD or Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. In October 2016, EPA issued a proposed rule to revise its PSD and Title V regulations applicable to GHGs in accordance with these court rulings, including proposing a de minimis level of GHG emissions below which BACT is not required. Depending on what EPA does in a final rule, it is possible that any regulatory or permitting obligation that limits emissions of GHGs could extend to smaller stationary sources and require us to incur costs to reduce and monitor emissions of GHGs associated with our operations and also adversely affect demand for the oil and natural gas that we produce.
In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including certain onshore oil and natural gas production sources, which include certain of our operations. While Congress has not enacted significant legislation relating to GHG emissions, it may do so in the future and, moreover, several state and regional initiatives have been enacted aimed at monitoring and/or reducing GHG emissions through cap and trade programs.
The adoption of new laws, regulations, or other requirements limiting or imposing other obligations on GHG emissions from our equipment and operations, and the implementation of requirements that have already been adopted, could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantial limitations on GHG emissions in other sectors, such as the power sector under EPA’s August 2015 Clean Power Plan, could adversely affect demand for the oil and natural gas that we produce. In February 2016, the U.S. Supreme Court stayed the Clean Power Plan pending judicial review. Further GHG regulation may result from the December 2015 agreement reached at the United Nations climate change conference in Paris. Pursuant to the agreement, the United States made an initial pledge to a 26-28% reduction in its GHG emission by 2025 against a 2005 baseline and committed to periodically update its pledge in five yearly intervals starting in 2020. GHG emissions in the earth’s atmosphere have also been shown to produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events, any of which could have an adverse effect on our operations.
Hydraulic Fracturing
We operate primarily in the Wattenberg Field of the D-J Basin where the rock formations are typically tight, and it is a common practice to use hydraulic fracturing to allow for or increase hydrocarbon production. Hydraulic fracturing involves the process of injecting substances such as water, sand, and additives (some proprietary) under pressure into a targeted subsurface formation to create fractures, thus creating a passageway for the release of oil and gas. Hydraulic fracturing is a technique that we commonly employ and expect to employ extensively in future wells that we drill and complete.
We outsource all hydraulic fracturing services to service providers with significant experience, and which we deem to be competent and responsible. Our service providers supply all personnel, equipment, and materials needed to perform each stimulation, including the chemical mixtures that are injected into our wells. We require our service companies to carry insurance covering various losses and liabilities that could arise in connection with their activities; however, insurance may not be available or adequate to cover losses and liabilities incurred, or may be prohibitively expensive relative to the perceived risk. In addition to the drilling permit that we are required to obtain and the notice of intent that we provide the appropriate regulatory authorities, our service providers are responsible for obtaining any regulatory permits necessary for them to perform their services in the relevant geographic location. We have not had any incidents, citations, or lawsuits relating to any environmental issues resulting from hydraulic fracturing, and we are not presently aware of any such matters.
In recent years, environmental opposition to hydraulic fracturing has increased, and various governmental and regulatory authorities have adopted or are considering new requirements for this process. To the extent that these requirements increase our costs or restrict our development activities, our business and prospects may be adversely affected.
The EPA has asserted that the Safe Drinking Water Act (“SDWA”) applies to hydraulic fracturing involving diesel fuel, and in February 2014, it issued final guidance on this subject. The guidance defines the term “diesel fuel,” describes the permitting requirements that apply under SDWA for the underground injection of diesel fuel in hydraulic fracturing, and makes recommendations for permit writers. Although the guidance applies only in those states, excluding Colorado, where the EPA directly implements the Underground Injection Control Class II program, it could encourage state regulatory authorities to adopt permitting and other requirements for hydraulic fracturing. In addition, from time to time, Congress has considered legislation that would provide for broader federal regulation of hydraulic fracturing under the SDWA. If such legislation were enacted, hydraulic fracturing operations could be required to meet additional federal permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and provide for additional public disclosure of the chemicals used in the fracturing process.
The EPA has also conducted a nationwide study into the effects of hydraulic fracturing on drinking water. In June 2015, the EPA released a draft study report for peer review and comment. The draft report did not find evidence of widespread systemic impacts to drinking water, but did find a relatively small number of site-specific impacts. The EPA noted that these results could indicate that such effects are rare or that other limiting factors exist. In December 2016, EPA released the final report on impacts from hydraulic fracturing activities on drinking water, concluding that hydraulic fracturing activities can impact drinking water resources under some circumstances and identifying some factors that could influence these impacts.
Federal agencies have also adopted or are considering additional regulation of hydraulic fracturing. On March 26, 2016, the U.S. Occupational Safety and Health Administration (“OSHA”) issued a final rule, with effective dates of 2018 and 2021 for the hydraulic fracturing industry, which imposes stricter standards for worker exposure to silica, including worker exposure to sand in hydraulic fracturing. In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act (“TSCA”) to obtain data on chemical substances and mixtures used in hydraulic fracturing. In March 2015, the Bureau of Land Management (“BLM”) issued a new rule regulating hydraulic fracturing activities involving federal and tribal lands and minerals, including requirements for chemical disclosure, wellbore integrity and handling of flowback and produced water. Due to pending litigation, however, the effective date of the rule has been postponed.
In November 2016, BLM finalized rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. The rules became effective in January 2017, but are subject to ongoing litigation.
In Colorado, the primary regulator is the COGCC, which has adopted regulations regarding chemical disclosure, pressure monitoring, prior agency notice, emission reduction practices, and offset well setbacks with respect to hydraulic fracturing operations and may in the future adopt additional requirements for this purpose. As part of these requirements, operators must report all chemicals used in hydraulically fracturing a well to a publicly searchable registry website developed and maintained by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission.
Apart from these ongoing federal and state initiatives, local governments are adopting new requirements and restrictions on hydraulic fracturing and other oil and gas operations. Some local governments in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, during the past few years, a total of five Colorado cities have passed voter initiatives temporarily or permanently prohibiting hydraulic fracturing. Since that time, however, local district courts have struck down the ordinances for certain of those Colorado cities, and such decisions were upheld by the Colorado Supreme Court in May 2016. Nevertheless, there is a continued risk that cities will adopt local ordinances that seek to regulate the time, place, and manner of hydraulic fracturing activities and oil and gas operations within their respective jurisdictions.
During 2014, opponents of hydraulic fracturing also sought statewide ballot initiatives that would have restricted oil and gas development in Colorado by, among other things, significantly increasing the setback between oil and natural gas wells and occupied buildings. These initiatives were withdrawn from the November 2014 ballot in return for the creation of a task force to craft recommendations for minimizing land use conflicts over the location of oil and natural gas facilities.
During 2016, opponents of hydraulic fracturing again advanced various options for ballot initiatives restricting oil and gas development in Colorado. Proponents of two such initiatives attempted to qualify the initiatives to appear on the ballot for the November 2016 election. One would have amended the Colorado constitution to impose a minimum distance of 2,500 feet between wells and any occupied structures or "areas of special concern". If implemented, this proposal would have made the vast majority of the surface area of the state ineligible for drilling, including substantially all of our planned future drilling locations. The second proposal would have amended the state constitution to give local governmental authorities the ability to regulate, or to ban, oil and gas exploration, development, and production activities within their boundaries notwithstanding state rules and approvals to the contrary. If implemented, this proposal could have resulted in us becoming subject to onerous, and possibly inconsistent, regulations that vary from jurisdiction to jurisdiction, or to outright bans on our activities in various jurisdictions. In August 2016, the Colorado Secretary of State issued a press release and statements of insufficiency of signatures, stating that the proponents of the proposals had failed to collect enough valid signatures to have the proposals included on the ballot. However, similar proposals may be made in the future. Because a substantial portion of our operations and reserves are located in Colorado, the risks we face with respect to such future proposals are greater than those of our competitors with more geographically diverse operations. Although we cannot predict the outcome of future ballot initiatives, statutes, or regulatory developments, such developments could materially impact our results of operations, production, and reserves.
ITEM 1A.
ITEM 1A.
RISK FACTORS
Investors should be aware that any purchase of our securities involves risks, including those described below, which could adversely affect the value of our common stock. We do not make, nor have we authorized any other person to make, any representation about the future market value of our common stock. In addition to the other information contained in this report, the following factors should be considered carefully in evaluating an investment in our securities.
Risks Relating to Our Business and the Industry
An extended or further decline in oil and natural gas prices may adversely affect our business, financial condition, or results of operations and our ability to meet our financial commitments.
The prices we receive for our oil and natural gas significantly affect many aspects of our business, including our revenue, profitability, access to capital, quantity and present value of proved reserves, and future rate of growth. Oil and natural gas are commodities, and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. In the recent past, benchmark oil prices have fallen from highs of over $100 per Bbl to lows below $30 per Bbl, and natural gas prices have experienced declines of comparable magnitude. Oil and natural gas prices will likely continue to be volatile in the future and will depend on numerous factors beyond our control. These factors include the following:
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worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
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the actions, or inaction, of OPEC;
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the price and quantity of imports of foreign oil and natural gas;
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political conditions or hostilities in oil-producing and natural gas-producing regions and related sanctions, including current conflicts in the Middle East and conditions in Africa, South America, and Russia;
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the level of global oil and domestic natural gas exploration and production;
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the level of global oil and domestic natural gas inventories;
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prevailing prices on local oil and natural gas price indexes in the areas in which we operate;
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localized supply and demand fundamentals and gathering, processing, and transportation availability;
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weather conditions and natural disasters;
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domestic and foreign governmental regulations;
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exports from the United States of liquefied natural gas or oil;
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speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;
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price and availability of competitors’ supplies of oil and natural gas;
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technological advances affecting energy consumption; and
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the price and availability of alternative fuels.
Lower oil and natural gas prices will reduce our cash flows and our borrowing ability. Our business has historically relied on the availability of additional capital, including proceeds from the sale of equity, debt, and convertible securities, to execute our business strategy. Further, our future growth strategy requires substantial additional capital, the availability of which will depend in significant part on current and expected commodity prices. If we are unable to raise capital on acceptable terms in the future, we may be unable to pursue our future acquisition, drilling, and development plans. While our current revolving credit facility provides for commitments of up to $500 million, actual borrowings may not exceed our borrowing base in effect at any time, which is subject to re-determination on a semi-annual basis. Our borrowing base is based in substantial part on the value of our oil and natural gas reserves which are, in turn, impacted by prevailing oil and natural gas prices. Accordingly, declining oil and natural gas prices have a direct impact on the amount that we can borrow under our revolving credit facility, which could affect our cash flows and ability to execute on our business plans. The next semi-annual redetermination of the borrowing base, which is currently $160 million, is scheduled to occur in May 2017. We may experience decreases in our borrowing base depending on future oil and natural gas prices. If our borrowing base declines significantly, we would have to either raise additional capital or adjust our drilling plan. In addition, if the lenders reduce the borrowing base below the then-outstanding balance, we will be required to repay the difference between the outstanding balance and the reduced borrowing base, and we may not have or be able to obtain the funds necessary to do so.
Furthermore, lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and may cause the value of our estimated proved reserves at future reporting dates to decline. Our estimated proved reserves as of December 31, 2015, and related PV-10 and standardized measure values, were calculated under SEC rules using twelve-month trailing average benchmark prices, adjusted by lease or field for quality, transportation fees, and regional price differentials, of $41.33 per barrel of oil (WTI) and $2.60 per MMBtu of natural gas (Henry Hub). The twelve-month trailing average benchmark prices, adjusted by lease or field for quality, transportation fees, and regional price differentials, used in
calculating proved reserves, PV-10 and standardized measure as of December 31, 2016 were $36.07 per barrel of oil (WTI) and $2.44 per MMBtu (Henry Hub). These lower prices adversely affected the estimated quantity and value of our proved reserves.
Furthermore, sustained periods of reduced oil and natural gas prices and the resultant effect such prices have on our drilling economics and our ability to raise capital would likely require us to re-evaluate and postpone or eliminate our development drilling, which would likely result in the reduction of some of our proved undeveloped reserves and PV-10 and standardized measure values, and would make it more difficult for us to achieve expected levels of production.
To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. If oil and natural gas prices decline, we will not be able to hedge future production at the same pricing level as our current hedges, and our results of operations and financial condition would be negatively impacted. In addition, hedging arrangements can expose us to risk of financial loss in some circumstances, including when production is less than expected, a counterparty to a hedging contract fails to perform under the contract, or there is a change in the expected differential between the underlying price in the hedging contract and the actual prices received.
Accordingly, any substantial or extended decline in the prices that we receive for our production would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations, and our results of operations.
Operating hazards may adversely affect our ability to conduct business.
Our operations are subject to risks inherent in the oil and gas industry, such as:
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unexpected drilling conditions including loss of well control, loss of drilling fluid circulation, cratering, and explosions;
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uncontrollable flows of oil, natural gas, or well fluids;
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equipment failures, fires, or accidents;
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pollution, releases of hazardous materials, and other environmental risks; and
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shortages in experienced labor or shortages or delays in the delivery of equipment or the performance of services.
These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage, and suspension of operations. We do not maintain insurance for all of these risks, nor in amounts that cover all of the losses to which we may be subject, and the insurance that we have may not continue to be available on acceptable terms. Moreover, some risks that we face are not insurable. For example, a leak or other pollution event may occur without our knowledge, making it impossible for us to notify the insurer within the time period required by the policy. Also, we could in some circumstances have liability for actions taken by third parties over which we have no or limited control, including operators of properties in which we have an interest. The occurrence of an uninsured or underinsured loss could result in significant costs that could have a material adverse effect on our financial condition and liquidity. In addition, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation, and development operations to be curtailed while those activities are being completed.
Our actual production, revenues, and expenditures related to our reserves are likely to differ from our estimates of proved reserves. We may experience production that is less than estimated, and drilling costs that are greater than estimated, in our reserve report. These differences may be material.
Although the estimates of our oil and natural gas reserves and future net cash flows attributable to those reserves were prepared by Ryder Scott, our independent petroleum and geological engineers, we are ultimately responsible for the disclosure of those estimates. Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:
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historical production from the area compared with production from similar producing wells;
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the assumed effects of regulations by governmental agencies;
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assumptions concerning future oil and natural gas prices; and
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assumptions concerning future operating costs, severance and excise taxes, development costs, and workover and remedial costs.
Because all reserve estimates are based on assumptions that may prove to be incorrect and are to some degree subjective, each of the following items may differ from those assumed in estimating proved reserves:
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the quantities of oil and natural gas that are ultimately recovered;
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the production and operating costs incurred;
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the amount and timing of future development expenditures; and
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future cash flows from the development of reserves.
Historically, there has been a difference between our actual production and the production estimated in a prior year’s reserve report. We cannot assure you that these differences will not be material in the future.
Approximately 81% of our estimated proved reserves at December 31, 2016 are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our estimates of proved undeveloped reserves reflect our plans to make significant capital expenditures to convert those reserves into proved developed reserves, including approximately $554.9 million in estimated capital expenditures during the five years ending December 31, 2021. The estimated development costs may not be accurate, development may not occur as scheduled, and results may not be as estimated. If we choose not to develop proved undeveloped reserves, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, proved undeveloped reserves generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may, therefore, be required to downgrade to probable or possible any proved undeveloped reserves that are not developed or expected to be developed within this five-year time frame.
You should not assume that the standardized measure of discounted cash flows is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the standardized measure of discounted cash flows from proved reserves at December 31, 2016 is based on twelve-month average prices and costs as of the date of the estimate. These prices and costs will change and may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by oil and natural gas purchasers or in governmental regulations or taxation may also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor we use when calculating standardized measure of discounted cash flows for reporting requirements in compliance with accounting requirements is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our operations or the oil and gas industry in general will affect the accuracy of our estimates of our oil and natural gas reserves. Each of the foregoing considerations also impacts the PV-10 values of our reserves.
Seasonal weather conditions, wildlife and plant species conservation restrictions, and other constraints could adversely affect our ability to conduct operations.
Our operations could be adversely affected by weather conditions and wildlife and plant species conservation restrictions. In Colorado, certain activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt operations. These constraints and resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operational and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.
Similarly, some of our properties are located in relatively populous areas in the Wattenberg Field, and our operations in those areas may be subject to additional expenses and limitations. For example, we may incur additional expenses in those areas to mitigate visual impacts, noise, and odor issues relating to our operations, and we may find it more difficult to obtain drilling permits and other governmental approvals. In addition, the risk of litigation related to our operations may be higher in those areas. Any of these factors could have a material impact on our operations in the Wattenberg Field and could have a material adverse effect on our business, financial condition, and results of operations.
Furthermore, a critical habitat designation for certain wildlife under the U.S. Endangered Species Act or similar state laws could result in material restrictions to public or private land use and could delay or prohibit land access or development. The listing of certain species as threatened or endangered could have a material adverse effect on our operations in areas where such listed species are found.
Our future success depends upon our ability to find, develop, produce, and acquire additional oil and natural gas reserves that are economically recoverable. Drilling activities may be unsuccessful or may be less successful than anticipated.
In order to maintain or increase our reserves, we must locate and develop or acquire new oil and natural gas reserves to replace those being depleted by production. We must do this even during periods of low oil and natural gas prices when it is difficult to raise the capital necessary to finance our exploration, development, and acquisition activities. Without successful exploration, development, or acquisition activities, our reserves and revenues will decline rapidly. We may not be able to find and develop or acquire additional reserves at an acceptable cost or have access to necessary financing for these activities, either of which would have a material adverse effect on our financial condition.
Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs, drilling results, and the accuracy of our assumptions and estimates regarding potential well communication issues and other matters affecting the spacing of our wells. Because of these uncertainties, we do not know if the numerous potential drilling locations that we have identified will ever be drilled or if we will be able to produce oil and natural gas from these or any other potential drilling locations. Many factors may cause us to curtail, delay, or cancel scheduled drilling projects, including factors relating to our receipt of drilling permits and other governmental approvals, shortages or delays in obtaining necessary equipment or services, equipment failures or accidents, adverse weather, environmental hazards, and title problems. As such, our actual drilling activities may differ materially from those presently identified, which could adversely affect our business and reserves.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient quantities to cover drilling, operating, and other costs. In addition, even a commercial well may have production that is less, or costs that are greater, than we projected. The cost of drilling, completing, and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. There can be no assurance that proved or unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such proved or unproved property or wells.
Acquisitions we pursue may not achieve their intended results and may result in us assuming unanticipated liabilities. These risks are heightened in the case of the GC Acquisition due to its size relative to our prior acreage position.
Pursuing acquisitions is an important part of our growth strategy. However, achieving the anticipated benefits of any acquisition is subject to a number of risks and uncertainties. For example, we may discover title defects or adverse environmental or other conditions related to the acquired properties of which we are unaware at the time that we enter into the relevant purchase and sale agreement. Environmental, title, and other problems could reduce the value of the acquired properties to us, and depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We may assume all or substantially all of the liabilities associated with the acquired properties and may be entitled to indemnification in connection with those liabilities in only limited circumstances and in limited amounts. We cannot assure that such potential remedies will be adequate for any liabilities that we incur, and such liabilities could be significant. Even though we perform due diligence reviews (including a review of title and other records) of the major properties that we seek to acquire that we believe are consistent with industry practices, these reviews are inherently incomplete. It is generally not feasible for us to perform an in-depth review of every individual property and all records involved in each acquisition. Moreover, even an in-depth review of records and properties may not necessarily reveal existing or potential liabilities or other problems or permit us to become familiar enough with the properties to assess fully their deficiencies and potential. The discovery of any material liabilities associated with our acquisitions could materially and adversely affect our business, financial condition, and results of operations. In addition, completing the integration process for any acquisition may be more expensive than anticipated, and we cannot assure you that we will be able to effect the integration of any acquired operations smoothly or efficiently or that the anticipated benefits of the transaction will be achieved. Further, acquisitions may require additional debt or equity financing, resulting in additional leverage or dilution of ownership.
The success of any acquisition will depend on, among other things, the accuracy of our assessment of the number and quality of the drilling locations associated with the properties to be acquired, future oil and natural gas prices, reserves and production, and future operating costs and various other factors. These assessments are necessarily inexact. Our assessment of certain of these factors will typically be based in part on information provided to us by the seller, including historical production data. Our independent reserve engineers typically will not provide a report regarding the estimates of reserves with respect to the properties to be acquired. The assumptions on which our internal estimates are based may prove to be incorrect in a number of material ways, resulting in our not realizing the expected benefits of the acquisition. As a result, we may not recover the purchase
price for the acquisition from the sale of production from the acquired properties or recognize an acceptable return from such sales.
We are subject to all of the foregoing risks with respect to the GC Acquisition, and these risks are heightened with respect to that acquisition due to the significant amount of acreage acquired relative to our prior acreage position. In addition, if the second closing of the GC Acquisition is delayed for a substantial period, we will not be able to control operations on the properties subject to that closing during that period, which would increase the risk that some leases will expire before production is established. This could materially detract from the value of the properties acquired pursuant to either closing. The second closing is subject to certain closing conditions, including our receipt of a release of a consent decree burdening certain of the properties to be acquired, and these conditions may not be satisfied in the time frame we expect or at all.
We may not be able to obtain adequate financing when the need arises to execute our long-term operating strategy.
Our ability to execute our long-term operating strategy is highly dependent on our having access to capital when the need arises. We historically have addressed our liquidity needs through credit facilities, issuances of equity, debt, and convertible securities, sales of assets, joint ventures, and cash provided by operating activities. We will examine the following alternative sources of capital in light of economic conditions in existence at the relevant time:
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borrowings from banks or other lenders;
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the sale of non-core assets;
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the issuance of debt securities;
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the sale of common stock, preferred stock, or other equity securities;
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joint venture financing; and
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production payments.
The availability of these sources of capital when the need arises will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices, our credit ratings, interest rates, market perceptions of us or the oil and gas industry, our market value, and our operating performance. We may be unable to execute our long-term operating strategy if we cannot obtain capital from these sources when the need arises, which would adversely affect our production, cash flows, and capital expenditure plans.
Oil and natural gas prices may be affected by local and regional factors.
The prices to be received for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process and transport our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional natural gas production and the actual (frequently lower) price that we receive for our production. Our average differential for the twelve months ended December 31, 2016 was $(8.77) per barrel for oil and $(0.08) per Mcf for natural gas. These differentials are difficult to predict and may widen or narrow in the future based on market forces. The unpredictability of future differentials makes it more difficult for us to effectively hedge our production. Our hedging arrangements are generally based on benchmark prices and therefore do not protect us from adverse changes in the differential applicable to our production.
Lower oil and natural gas prices and other adverse market conditions may cause us to record ceiling test write-downs or other impairments, which could negatively impact our results of operations.
We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for, and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If, at the end of any fiscal period, we determine that the net capitalized costs of oil and gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity. Once incurred, a write-down of oil and gas properties is not reversible at a later date.
We review the net capitalized costs of our properties quarterly, using a single price based on the beginning-of-the-month average of oil and natural gas prices for the preceding 12 months. We also assess investments in unproved properties periodically to determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we
experience substantial downward adjustments to our estimated proved reserves or our unproved property values or if estimated future development costs increase.
The ceiling test calculation as of December 31, 2016 used average realized prices of $36.07 per barrel and $2.44 per Mcf. The oil prices used at December 31, 2016 were approximately 13% lower than the December 31, 2015 price of $41.33 per barrel, and the gas prices were approximately 6% lower than the December 31, 2015 price of $2.60 Mcf. We compare our net capitalized costs for oil and gas properties to the ceiling amount at various points during the year. At March 31, 2016, June 30, 2016, and September 30, 2016, our net capitalized costs for oil and gas properties exceeded the ceiling amount by $45.6 million, $144.1 million, and $25.5 million, respectively, resulting in a total ceiling test write-down of $215.2 million for the year ended December 31, 2016. We may experience further ceiling test write-downs in the future. Any future ceiling test cushion, and the risk we may incur further write-downs or impairments, will be subject to fluctuation as a result of acquisition or divestiture activity. In addition, declining commodity prices or other adverse market conditions, such as declines in the market price of our common stock, could result in goodwill impairments or reductions in proved reserve estimates that would adversely affect our results of operation or financial condition.
We cannot control the activities on properties that we do not operate, and we are unable to ensure the proper operation and profitability of these non-operated properties.
We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others, therefore, will depend upon a number of factors outside of our control, including the operator’s:
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timing and amount of capital expenditures;
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expertise and diligence in adequately performing operations and complying with applicable agreements;
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financial resources;
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inclusion of other participants in drilling wells; and
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use of technology.
As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected. In addition, our lack of control over non-operated properties makes it more difficult for us to forecast future capital expenditures and production.
We are dependent on third party pipeline, trucking, and rail systems to transport our production and gathering and processing systems to prepare our production. These systems have limited capacity and, at times, have experienced service disruptions. Curtailments, disruptions, or lack of availability in these systems interfere with our ability to market the oil and natural gas we produce and could materially and adversely affect our cash flow and results of operations.
Market conditions or the unavailability of satisfactory oil and gas transportation and processing arrangements may hinder our access to oil and natural gas markets or delay our production. The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of gathering, processing, pipeline, trucking, and rail systems. The amount of oil and natural gas that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, accidents, excessive pressure, physical damage to the gathering or transportation system, lack of contracted capacity on such systems, inclement weather, labor or regulatory issues, or other interruptions. A portion of our production may be interrupted, or shut in, from time to time as a result of these factors. Curtailments and disruptions in these systems may last from a few days to several months or longer. These risks are greater for us than for some of our competitors because our operations are focused on areas where there has been a substantial amount of development activity in recent years and resulting increases in production, and this has increased the likelihood that there will be periods of time in which there is insufficient midstream capacity to accommodate the increased production. For example, the gas gathering systems serving the Wattenberg Field have in recent years experienced high line pressures, and at times, this has reduced capacity and caused gas production to either be shut in or flared. In addition, we might voluntarily curtail production in response to market conditions. Any significant curtailment in gathering, processing or pipeline system capacity, significant delay in the construction of necessary facilities, or lack of availability of transport would interfere with our ability to market the oil and natural gas that we produce and could materially and adversely affect our cash flow and results of operations and the expected results of our drilling program.
We may be unable to satisfy our contractual obligations, including obligations to deliver oil and natural gas from our own production or other sources.
We have entered into agreements that require us to deliver minimum amounts of oil to three counterparties that transport oil via pipelines. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil we acquire, over the next five years. Since October 2015, we have been obligated to deliver a combined volume of 6,157 Bbls of oil per day to two of these counterparties. We have also committed to deliver 5,000 Bbls of oil per day to the third counterparty for five years beginning in the latter half of 2016. If we are unable to fulfill all of our contractual obligations from our own production or from oil and natural gas that we acquire from third parties, we may be required to pay penalties or damages pursuant to these agreements. We incurred such charges in the amount of $0.6 million during the year ended December 31, 2016.
Furthermore, in collaboration with several other producers and DCP Midstream, we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin. As a result of this agreement, we have committed to deliver 46.4 MMcf of natural gas per day for a period of 7 years from the plant in-service date, which is currently expected to be in late 2018. We may be required to pay penalties or damages pursuant to this agreement if we are unable to fulfill all of our contractual obligation from our own production and if the collective volumes delivered to the plant by other producers in the D-J Basin are not in excess of the total commitment.
Any future penalties or damages of the types described above could adversely impact our cash flows, profit margins, net income, and reserve values.
We face strong competition from larger oil and natural gas companies that may negatively affect our ability to carry on operations.
We operate in the highly competitive areas of oil and gas exploration, development, and production. Factors that affect our ability to compete successfully in the marketplace include:
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the availability of funds for, and information relating to, properties;
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the standards established by us for the minimum projected return on investment; and
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the transportation of natural gas and oil.
Our competitors include major integrated oil companies, substantial independent energy companies, affiliates of major interstate and intrastate pipelines, and national and local gas gatherers, many of which possess greater financial and other resources than we do. If we are unable to successfully compete against our competitors, our business, prospects, financial condition, and results of operations may be adversely affected.
We may be unable to successfully identify, execute, or effectively integrate future acquisitions, which may negatively affect our results of operations.
Acquisitions of oil and gas businesses and properties have been an important element of our business, and we will continue to pursue acquisitions in the future. Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition, or if the acquisition occurs, effectively integrate the acquired business or properties into our existing business. Negotiations of potential acquisitions and the integration of acquired assets may require a disproportionate amount of management’s attention and our resources. Moreover, our debt agreements contain covenants that may limit our ability to finance an acquisition. Even if we complete additional acquisitions, any new assets may not generate revenues comparable to our existing business, the anticipated cost efficiencies or synergies may not be realized, and the acquired assets may not be integrated successfully or operated profitably. Our inability to successfully identify, execute, or effectively integrate future acquisitions may negatively affect our results of operations.
We may incur substantial costs to comply with the various federal, state, and local laws and regulations that affect our oil and natural gas operations.
We are affected significantly by a substantial number of governmental regulations that increase costs related to the drilling, completion, production, and abandonment of wells, the transportation and processing of oil and natural gas, the management and disposal of waste, and other aspects of our operations. It is possible that the number and extent of these regulations, and the costs to comply with them, will increase significantly in the future. In Colorado, for example, significant governmental regulations have been adopted in recent years to address well siting, well construction, hydraulic fracturing, water quality, public safety, air
emissions, aesthetics, waste management, spill reporting, land reclamation, wildlife protection, and data collection. These government regulatory requirements may result in substantial costs that are not possible to pass through to our customers and could impact the profitability of our operations.
Our operations are subject to stringent federal, state, and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to health and safety, land use, environmental protection, or the oil and gas industry generally. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Compliance with such laws and regulations often increases our cost of doing business and, in turn, decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the incurrence of investigatory or remedial obligations, or the issuance of cease and desist orders.
The environmental laws and regulations to which we are subject may, among other things:
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require us to apply for and receive a permit before drilling commences or certain associated facilities are developed;
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restrict the types, quantities, and concentrations of substances that can be released into the environment in connection with drilling, hydraulic fracturing, and production activities;
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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other "waters of the United States," threatened and endangered species habitat, and other protected areas;
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require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and
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impose substantial liabilities for pollution resulting from our operations.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal, or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our earnings, results of operations, competitive position, or financial condition. Changes to the requirements for drilling, completing, operating, and abandoning wells and related facilities could have similar adverse effects on us.
New environmental legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays.
We are subject to extensive federal, state, and local laws and regulations concerning health, safety, and environmental protection. Government authorities frequently add to those requirements, and both oil and gas development generally and hydraulic fracturing specifically are receiving increased regulatory attention. Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulate hydrocarbon production.
In 2012, the EPA issued final rules that establish new air emission controls for natural gas processing operations as well as for oil and natural gas production. Among other things, the rules cover the completion and operation of hydraulically fractured natural gas wells and associated equipment. After several parties challenged the new air regulations in court, the EPA reconsidered certain requirements and amended the rules in 2013 and 2014. In June 2016, the EPA finalized new regulations that set methane and volatile organic compounds emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of an effort to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. In addition, on March 10, 2016, EPA announced that it will begin a formal process under CAA § 111(d) to require companies operating existing oil and gas sources to provide information to assist EPA in developing comprehensive regulations to reduce methane emissions. In late 2016, EPA sent ICRs to operators to gather information on existing sources of methane emissions, technologies to reduce those emissions, and the costs of those technologies in the production, gathering, processing, and transmission and storage segments of the oil and natural gas sector. In addition, in October 2015, the EPA lowered the NAAQS for ozone under the CAA from 75 parts per billion to 70 parts per billion. Any resulting expansion of the ozone nonattainment areas in Colorado could cause our oil and natural gas operations in such areas to become subject to more stringent emissions controls, emission offset requirements and increased permitting delays and costs. In addition, the ozone nonattainment status for the Denver Metro North Front Range Ozone 8-Hour Non-Attainment area was bumped up by the EPA from “marginal” to “moderate” as a result of the area failing to attain the 2008 ozone NAAQS by the applicable attainment date of July 20, 2015. In 2016, the state of Colorado undertook a rulemaking to address the new “moderate” status, culminating in, among other things, the incorporation of two existing state-only requirements for oil and natural gas operations into the federally-enforceable SIP. During the fall of 2016, EPA also issued final CTGs for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Metro North Front Range Ozone 8-hour Non-Attainment area. In 2017, as part of the federal CTG process for oil and natural gas, Colorado will begin a stakeholder and rulemaking effort to compare the CTGs to existing Colorado requirements to ensure they meet applicable federal requirements. This process could result in new or more stringent air quality control requirements applicable to our operations.
Several governmental reviews are underway assessing the impact of hydraulic fracturing on the environment and human health and safety, including potential adverse effects on drinking water supplies as well as migration of methane and other hydrocarbons. As a result, the federal government is studying the environmental risks associated with hydraulic fracturing and evaluating whether to adopt additional regulatory requirements. For example, the EPA has conducted a multi-year study of the potential impacts of hydraulic fracturing on drinking water resources, and the draft results were released for public and peer review in June 2015. In December 2016, EPA released the final report on impacts from hydraulic fracturing activities on drinking water, concluding that hydraulic fracturing activities can impact drinking water resources under some circumstances and identifying some factors that could influence these impacts. In addition, in February 2014, the EPA issued final guidance for underground injection permits that regulate hydraulic fracturing using diesel fuel, where the EPA has permitting authority under the SDWA. This guidance eventually could encourage other regulatory authorities to adopt permitting and other restrictions on the use of hydraulic fracturing. In May 2014, the EPA issued an advance notice of proposed rulemaking under the TSCA to obtain data on chemical substances and mixtures used in hydraulic fracturing. In October 2015, EPA also granted, in part, a petition filed by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals" under the Toxics Release Inventory ("TRI") program. EPA determined that natural gas processing facilities may be appropriate for addition to the scope of TRI and will conduct a rulemaking process to propose such action. In January 2017, EPA issued a proposed rule to include natural gas processing facilities within the TRI program. In June 2016, the EPA finalized CWA pretreatment standards on wastewater discharges associated with hydraulic fracturing activities. Aside from the EPA, the BLM has issued new rules, which are currently stayed pending further litigation, for hydraulic fracturing activities involving federal and tribal lands and minerals that, in general, would cover disclosure of fracturing fluid components, wellbore integrity, and handling of flowback and produced water. In March 2016, OSHA issued a final rule, with effective dates of 2018 and 2021 for the hydraulic fracturing industry, which imposes stricter standards for worker exposure to silica, including worker exposure to sand in hydraulic fracturing. In addition, OSHA and the National Institute of Occupational Safety and Health have issued hazard alerts to the hydraulic fracturing industry regarding risks to workers from silica exposure and other hazards, which include recommendations to reduce those risks and proposals for additional study of the industry. In December 2015, the U.S. Department of Labor and the U.S. Department of Justice released a Memorandum of Understanding ("MOU"), announcing an interagency effort to increase enforcement of worker endangerment violations under environmental statutes (such as the Clean Water Act, the Clean Air Act, and the RCRA) and Title 18 criminal statutes that carry harsher penalties than the Occupational Safety and Health Act of 1970. Consistent with this MOU, where appropriate, the Department of Justice will seek felony charges (such as false statements, conspiracy, and obstruction of justice) when prosecuting worker endangerment violations.
In the United States Congress, bills have been introduced from time to time that would amend the SDWA to eliminate an existing exemption for certain hydraulic fracturing activities from the definition of "underground injection," thereby requiring oil and gas companies to obtain SDWA permits for fracturing not involving diesel fuels, and to require disclosure of the chemicals used in the process. If adopted, such legislation could establish an additional level of regulation and permitting at the federal level, although some form of chemical disclosure is already required by most oil and gas producing states. At this time, it is not clear what action, if any, the United States Congress will take to address hydraulic fracturing.
Apart from these ongoing federal initiatives, state governments where we operate have moved to impose stricter requirements on hydraulic fracturing and other aspects of oil and natural gas production. Colorado, for example, comprehensively updated its oil and gas regulations in 2008 and adopted significant additional amendments in 2011, 2013, 2014, and 2015. Among other things, the updated and amended regulations require operators to reduce methane emissions associated with hydraulic fracturing, compile and report additional information regarding wellbore integrity, satisfy more stringent reclamation and remediation standards, avoid certain wildlife habitat, publicly disclose the chemical ingredients used in hydraulic fracturing, increase the minimum distance between occupied structures and oil and natural gas wells, undertake additional mitigation for nearby residents, implement additional groundwater testing, and take additional actions to prevent blowouts and avoid subsurface well communication. Colorado has also adopted new regulations for air emissions from oil and natural gas operations as well as new legislation and implementing regulations increasing the monetary penalties for regulatory violations and lowering the threshold for reporting spills. Additionally, local governments are adopting new requirements on hydraulic fracturing and other oil and natural gas operations, including local county and city governments in Colorado.
In January 2016, the COGCC approved new rules that require local government consultation and certain best management practices for large-scale oil and natural gas facilities in certain urban mitigation areas. The new rules also require operator registration and/or notifications to local governments with respect to future oil and natural gas drilling and production facility locations.
In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas.
The trend toward stricter standards and greater enforcement in environmental legislation and regulation is likely to continue. For example, concern has recently arisen in several states over increasing numbers of earthquakes that may be associated with underground injection wells used for the disposal of oil and gas wastewater. Such concerns could eventually limit the use of such wells in some areas and increase the cost of disposal in others. Similarly, concerns have recently been expressed over the flaring of natural gas associated with oil production in some areas. These concerns and regulations could limit or increase the cost of oil production in some areas. Other environmental issues and concerns may arise from time to time in the future and lead to new and additional legislative and regulatory initiatives.
The adoption of future federal, state, or local laws or implementing regulations or orders imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of resources (especially from shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products. Any such outcome could have a material and adverse impact on our cash flows and results of operations.
Any local moratoria or bans on our activities could have a negative impact on our business, financial condition, and results of operations.
Some local governments are adopting new requirements and restrictions on hydraulic fracturing and other oil and natural gas operations. Some local governments in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, during the past few years, a total of five Colorado cities have passed voter initiatives temporarily or permanently prohibiting hydraulic fracturing. Since that time, local district courts have struck down the ordinances for certain of those Colorado cities, and such decisions were upheld by the Colorado Supreme Court in May 2016. Nevertheless, there is a continued risk that cities will adopt local ordinances that seek to regulate the time, place, and manner of hydraulic fracturing activities and oil and natural gas operations within their respective jurisdictions.
In addition, in 2014 and 2016, opponents of hydraulic fracturing sought statewide ballot initiatives that would have restricted oil and gas development in Colorado. The 2014 initiatives were withdrawn in return for the creation of a task force to craft recommendations for minimizing land use conflicts over the location of oil and natural gas facilities, and none of the 2016 initiatives were successful. We cannot predict the nature or outcome of future ballot initiatives, which could materially impact our results of operations, production, and reserves. If we are required to cease operating in any of the areas in which we now operate as the result of bans or moratoria on drilling or related oilfield services activities, it could have a material effect on our business, financial condition, and results of operations.
Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas that we produce. Potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
In 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic conditions. Based on these findings, the EPA adopted regulations under the CAA that, among other things, established PSD, construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already major sources of emissions of regulated pollutants. In a subsequent ruling, the U.S. Supreme Court upheld a portion of EPA’s GHG stationary source program, but invalidated a portion of it. The Court held that stationary sources already subject to the PSD or Title V program for non-GHG criteria pollutants remained subject to GHG BACT requirements, but ruled that sources subject to the PSD or Title V program only for GHGs could not be forced to comply with GHG BACT requirements. Upon remand, the D.C. Circuit issued an amended judgment, which, among other things, vacated the PSD and Title V regulations under review in that case to the extent they require a stationary source to obtain a PSD or Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. In October 2016, EPA issued a proposed rule to revise its PSD and Title V regulations applicable to GHGs in accordance with these court rulings, including proposing a de minimis level of GHG emissions below which BACT is not required. Depending on what EPA does in a final rule, it is possible that any regulatory or permitting obligation that limits emissions of GHGs could extend to smaller stationary sources and require us to incur costs to reduce and monitor emissions of GHGs associated with our operations and also adversely affect demand for the oil and natural gas that we produce.
In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including certain onshore oil and natural gas production sources, which include certain of our operations. While Congress has not enacted significant legislation relating to GHG emissions, it may do so in the future,
and moreover, several state and regional initiatives have been enacted aimed at monitoring and/or reducing GHG emissions through cap and trade programs.
The adoption of new laws, regulations, or other requirements limiting or imposing other obligations on GHG emissions from our equipment and operations, and the implementation of requirements that have already been adopted, could require us to incur costs to reduce emissions of GHGs associated with our operations, including those regulating methane emissions from the oil and gas industry. See the risk factor above entitled "New environmental legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays" for further information regarding methane emissions regulations. In addition, substantial limitations on GHG emissions in other sectors, such as the power sector under EPA's August 2015 Clean Power Plan, could adversely affect demand for the oil and natural gas that we produce. In February 2016, the U.S. Supreme Court stayed the Clean Power Plan pending judicial review. Further, GHG regulation may result from the December 2015 agreement reached at the United Nations climate change conference in Paris. Pursuant to the agreement, the United States made an initial pledge to a 26-28% reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update its pledge in five yearly intervals starting in 2020. GHG emissions in the earth's atmosphere have also been shown to produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events, any of which could have an adverse effect on our operations.
Environmental liabilities relating to activities of other parties could have a material adverse effect on our financial condition and operations.
Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, and other environmental damages, including as a result of the activities of previous owners of our properties. We could incur substantial liabilities to third parties or governmental entities, which could have a material adverse effect on our financial condition and results of operations. For example, over the years, we have owned or leased numerous properties for oil and natural gas activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including CERCLA, RCRA, and state laws, we could be held liable for the removal or remediation of previously released materials or property contamination at such locations, or at third-party locations to which we have sent waste, regardless of whether we were responsible for the release or whether the operations at the time of the release were standard industry practice.
Similarly, the OPA imposes a variety of regulations on “responsible parties” related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the OPA, could have a material adverse impact on us.
The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital required to conduct these activities.
The Dodd-Frank Act authorizes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. Regulations under the Dodd-Frank Act may, among other things, require us to comply with margin requirements in connection with our derivative activities. If we are required to post cash collateral in connection with some or all of our derivative positions, this would make it difficult or impossible to pursue our current hedging strategy. The regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The regulations may also reduce the number of potential counterparties in the market, which could make hedging more expensive.
If we reduce our use of derivatives as a result of the Dodd-Frank Act and its implementing regulations, our results of operations may be more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on our financial position, results of operations, and cash flows. In addition, derivative instruments create a risk of financial loss in some circumstances, including when production is less than the volume covered by the instruments.
Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations, and cash flows.
From time to time, legislative proposals are made that would, if enacted, result in significant changes to U.S. tax laws. These proposed changes have included, among others, eliminating the immediate deduction for intangible drilling and development costs, eliminating the deduction from income for domestic production activities relating to oil and gas exploration and development, repealing the percentage depletion allowance for oil and gas properties and extending the amortization period for certain geological
and geophysical expenditures. Such proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and gas exploration and development, could adversely affect our business, financial condition, results of operations, and cash flows.
Our indebtedness adversely affects our cash flow and may adversely affect our ability to operate our business. Our ability to remain in compliance with debt covenants and make payments on our debt is subject to numerous risks.
As of December 31, 2016, the aggregate amount of our outstanding indebtedness was $80 million. Our indebtedness could have important consequences for investors, including the following:
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the covenants contained in our debt agreements limit our ability to borrow money in the future for acquisitions, capital expenditures, or to meet our operating expenses or other general corporate obligations and may limit our flexibility in operating our business;
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the amount of our interest expense may increase because amounts borrowed under our credit facility bear interest at variable rates, payable either quarterly or at the end of a specified interest period; if interest rates increase, this could result in higher interest expense; and
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our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.
Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory, and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, sell assets, borrow more money, or raise equity. We may not be able to refinance our debt, sell assets, borrow more money, or raise equity on terms acceptable to us, if at all.
Any failure to meet our debt obligations could harm our business, financial condition, and results of operations.
Our ability to make payments on and/or to refinance our indebtedness and to fund planned capital expenditures will depend on our ability to generate sufficient cash flow from operations in the future. To a significant extent, this is subject to general economic, financial, competitive, legislative and regulatory conditions, and other factors that are beyond our control, including the prices that we receive for our oil and natural gas production.
We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our credit facility in an amount sufficient to enable us to pay principal and interest on our indebtedness or to fund our other liquidity needs. For example, decreases in oil and natural gas prices in the recent past have adversely affected our ability to generate cash flow from operations and future decreases would have similar effects. If our cash flow and existing capital resources are insufficient to fund our debt obligations, we may be forced to reduce our planned capital expenditures, sell assets, seek additional equity or debt capital, or restructure our debt, and any of these actions, if completed, could adversely affect our business and/or our shareholders. We cannot assure you that any of these remedies could, if necessary, be effected on commercially reasonable terms, in a timely manner or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could impair our liquidity.
Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions, and engage in other business activities that may be in our best interests.
Our credit facility and the indenture governing our Senior Notes contain, and future debt agreements may contain, covenants that restrict or limit our ability to:
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pay dividends or distributions on our capital stock or issue preferred stock;
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repurchase, redeem, or retire our capital stock or subordinated debt;
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make certain loans and investments;
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sell assets;
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enter into certain transactions with affiliates;
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create or assume certain liens on our assets;
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enter into sale and leaseback transactions;
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merge or enter into other business combination transactions; or
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engage in certain other corporate activities.
Our credit facility also requires us to satisfy certain financial tests on an ongoing basis. Our ability to comply with these requirements may be affected by events beyond our control, and we cannot assure you that we will satisfy them in the future. In addition, these requirements could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the restrictive covenants under our debt agreements. Future debt agreements may have similar, or more restrictive, provisions.
A breach of any of the covenants in our debt agreements could result in a default under the agreement. A default, if not cured or waived, could result in all indebtedness outstanding under the agreement and other debt agreements becoming immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts, the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.
We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.
We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing, and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such unpaid costs and liabilities arising from the actions of other working interest owners. In addition, declines in commodity prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, will not be able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover them from our partners. This could materially adversely affect our financial position.
Our disclosure controls and procedures may not prevent or detect potential acts of fraud.
Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in reports we file or submit under the Exchange Act is accumulated and communicated to management, and recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms.
Our management, including our Chief Executive Officer and Chief Financial Officer, believes that any disclosure controls and procedures or internal controls and procedures, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, they cannot provide absolute assurance that all control issues and instances of fraud, if any, within our company have been prevented or detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by an unauthorized override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and we cannot assure you that any design will succeed in achieving its stated goals under all potential future conditions. Accordingly, because of the inherent limitations in a cost effective control system, misstatements due to error or fraud may occur and not be detected.
Failure to maintain an effective system of internal control over financial reporting may have an adverse effect on our stock price.
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the SEC to implement Section 404, we are required to furnish a report by our management in this report regarding the effectiveness of our internal control over financial reporting. The report includes, among other things, an assessment of the effectiveness of our internal control over financial reporting as of the end of our fiscal year, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by management. If we are unable to assert that our internal control over financial reporting is effective now or in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internal controls, investors
could lose confidence in the accuracy and completeness of our financial reports, which could have an adverse effect on our stock price.
Substantially all of our producing properties are located in the D-J Basin in Colorado, making us vulnerable to risks associated with operating in one major geographic area.
Our operations have been focused on the D-J Basin in Colorado, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil and natural gas produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production, or interruption of transportation and processing services, and any resulting delays or interruptions of production from existing or planned new wells. For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field, the demand for, and cost of, drilling rigs, equipment, supplies, personnel, and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel, or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition, or results of operations.
The inability of one or more of our customers to meet their obligations may adversely affect our financial results.
Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. We sell production to a small number of customers, as is customary in the industry. For the twelve months ended December 31, 2016, we had four major customers, which represented 20%, 20%, 16%, and 13% of our revenue during the period. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties.
Failure to adequately protect critical data and technology systems could materially affect our operations.
Information technology solution failures, network disruptions, and breaches of data security could cause delays or cancellation of transactions, impede processing of transactions and reporting financial results, or cause inadvertent disclosure of non-public information or other problems, any of which could result in disruptions to our operations, liability to third parties, or damage to our reputation. A system failure or data security breach may have a material adverse effect on our financial condition, results of operations, or cash flows.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain or dispose of water at a reasonable cost and in compliance with applicable regulations may have a material adverse effect on our financial condition, results of operations, and cash flows.
Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. When drought conditions occur, governmental authorities may restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. Colorado has a relatively arid climate and experiences drought conditions from time to time. If we are unable to obtain water to use in our operations from local sources or dispose of or recycle water used in operations, or if the price of water or water disposal increases significantly, we may be unable to produce oil and natural gas economically, which could have a material adverse effect on our financial condition, results of operations, and cash flows. The quantity of water required for hydraulic fracturing, and changing regulations governing usage, may lead to water constraints and supply concerns, particularly in some parts of the country. As a result, future availability of water from some sources used in the past may become limited.
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could materially and adversely affect our business. The risk of lease expiration typically increases at times when commodity prices are depressed, as the pace of our exploration and development activity tends to slow during such periods. The GC Acquisition increased these risks for us as a large portion of the acreage we acquired in the transaction is undeveloped.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. As of December 31, 2016, we operated 110 gross horizontal producing wells, with an additional 49 horizontal wells waiting on completion, and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore, and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations, and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. Also, we generally use multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less successful than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or unfavorable commodity prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and gas properties, and the value of our undeveloped acreage could decline.
Risks Relating to our Common Stock
We do not intend to pay dividends on our common stock, and our ability to pay dividends on our common stock is restricted.
Since inception, we have not paid any cash dividends on our common stock. Cash dividends are restricted under the terms of our debt agreements, and we presently intend to continue the policy of using retained earnings for expansion of our business. Any future dividends also may be restricted by future agreements.
The price of our stock price has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.
The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable future. Adverse events, including, among others:
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changes in production volumes, worldwide demand and prices for oil and natural gas;
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changes in market prices of oil and natural gas;
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changes in securities analysts’ estimates of our financial performance;
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fluctuations in stock market prices and volumes, particularly among securities of energy companies;
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changes in market valuations of similar companies;
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changes in interest rates;
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announcements regarding adverse timing or lack of success in discovering, acquiring, developing, and producing oil and natural gas resources;
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announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments;
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decreases in the amount of capital available to us;
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operating results that fall below market expectations or variations in our quarterly operating results;
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loss of a major customer;
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loss of a relationship with a partner;
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the identification of and severity of environmental events and governmental and other third-party responses to the events; or
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additions or departures of key personnel,
could trigger significant declines in the price of our common stock. External events, such as news concerning economic conditions, counterparties to our natural gas or oil derivatives arrangements, changes in government regulations impacting the oil and gas exploration and production industries, actual and expected production levels from OPEC members and other oil-producing countries and the movement of capital into or out of our industry, also are likely to affect the price of our common stock, regardless of our operating performance. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock. Recently, the stock markets have experienced price and volume volatility that has affected many companies' stock prices. Stock prices for many companies have experienced wide fluctuations that have often been unrelated to the operating performance of those companies. These fluctuations may affect the market price of our common stock.
Additional financings may subject our existing stockholders to significant dilution.
To the extent that we raise additional funds or complete acquisitions by issuing equity securities, our stockholders may experience significant dilution. In addition, debt financing, if available, may involve restrictive covenants. We may seek to access the public or private capital markets whenever conditions are favorable, even if we do not have an immediate need for additional capital at that time. Our access to the financial markets and the pricing and terms that we receive in those markets could be adversely impacted by various factors, including changes in general market conditions and commodity price changes.
Equity compensation plans may cause a future dilution of our common stock.
To the extent options to purchase common stock under our equity incentive plans are exercised, or shares of restricted stock or other equity awards are issued based on satisfaction of vesting requirements, holders of our common stock will experience dilution.
As of December 31, 2016, there were 9,519,584 shares reserved for issuance under our equity compensation plans, of which 890,336 restricted shares have been granted and are subject to vesting in the future based on the satisfaction of certain criteria established pursuant to the respective awards, 478,510 performance-based restricted shares have been granted and are subject to future issuance based on the Company's total shareholder return relative to a selected peer group of companies over the performance period, and 6,001,500 of which are issuable upon the exercise of outstanding options to purchase common stock. Our outstanding options have a weighted average exercise price of $9.27 per share as of December 31, 2016.
Non-U.S. holders of our common stock, in certain situations, could be subject to U.S. federal income tax upon sale, exchange, or disposition of our common stock.
It is likely that we are, and will remain for the foreseeable future, a U.S. real property holding corporation for U.S. federal income tax purposes because our assets consist primarily of "United States real property interests" as defined in the applicable Treasury regulations. As a result, under the Foreign Investment in Real Property Tax Act ("FIRPTA"), certain non-U.S. investors may be subject to U.S. federal income tax on gain from the disposition of shares of our common stock, in which case they would also be required to file U.S. tax returns with respect to such gain, and may be subject to a withholding tax. In general, whether these FIRPTA provisions apply depends on the amount of our common stock that such non-U.S. investors hold and whether, at the time they dispose of their shares, our common stock is regularly traded on an established securities market within the meaning of the applicable Treasury regulations. So long as our common stock continues to be regularly traded on an established securities market, only a non-U.S. investor who has owned, actually or constructively, more than 5% of our common stock at any time during the shorter of (i) the five-year period ending on the date of disposition and (ii) the non-U.S. investor's holding period for its shares may be subject to U.S. federal income tax on the disposition of our common stock under FIRPTA.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
See Item 1 of this report.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
On June 1, 2015, the Company filed a complaint in the District Court of Weld County, Colorado, against Briller, Inc., R.W.L. Enterprises, and Robert W. Loveless (together, the "Defendants") arising from a dispute concerning the validity of certain leases covering oil and gas properties in Weld County, Colorado. In June 2015, the Defendants removed the case to the Federal District Court of Colorado and filed an answer and counterclaims including claims for trespass. The Company and Defendants entered into a settlement agreement on December 6, 2016, resolving all claims and counterclaims related to the litigation. The terms of the settlement agreement do not have a material effect on the Company.
In July 2016, we were informed by the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division ("CDPHE") that it expects to expand its inspection of the Company's facilities in connection with a Compliance Advisory previously issued by the CDPHE and subsequent inspections conducted by the CDPHE. The Compliance Advisory alleged issues at five Company facilities regarding leakages of volatile organic compounds from storage tanks, all of which were promptly addressed. A subsequent February 2017 tolling agreement between the Company and CDPHE addressed alleged similar storage tank leakage issues at other Company facilities in Colorado. We are working with the CDPHE to respond to any continuing concerns. We cannot predict the outcome of this matter, but we expect that any potential resolution of these claims would be on a field-wide basis.
ITEM 4.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed on the NYSE MKT under the symbol “SYRG”.
Shown below is the range of high and low sales prices for our common stock as reported by the NYSE MKT for the past two years.
As of January 31, 2017, the closing price of our common stock on the NYSE MKT was $8.61.
As of January 31, 2017, we had 200,674,003 outstanding shares of common stock and 96 shareholders of record.
Since inception, we have not paid any cash dividends on common stock. Cash dividends are restricted under the terms of our debt agreements, and we presently intend to continue the policy of using retained earnings for expansion of our business.
Issuer Purchases of Equity Securities
(1) Pursuant to statutory minimum withholding requirements, certain of our employees and executives exercised their right to "withhold to cover" as a tax payment method for the vesting and exercise of certain shares. These elections were outside of a publicly announced repurchase plan.
Comparison of Cumulative Return
The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2016, with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the companies with a Standard Industrial Code ("SIC") of 1311. The SIC Code 1311 consists of a weighted average composite of publicly traded oil and gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on August 31, 2011 and in the S&P 500 Index and all companies with the SIC Code 1311 on the same date. The results shown in the graph below are not necessarily indicative of future performance.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
The selected financial data presented in this item has been derived from our audited consolidated financial statements that are either included in this report or in reports previously filed with the SEC. The information in this item should be read in conjunction with the consolidated financial statements and accompanying notes and other financial data included in this report.
1 Depletion, Depreciation, & Accretion
On February 25, 2016, we changed our fiscal year from the period beginning on September 1 and ending on August 31 to the period beginning on January 1 and ending on December 31. As a result, the selected financial data above includes financial information for the transition period from September 1, 2015 through December 31, 2015. This financial information may not be directly comparable to the prior periods as it covers a shorter time frame.
See Note 19 to the consolidated financial statements included as part of this report for our quarterly financial data. See Note 1 and Note 3 to the consolidated financial statements included as part of this report for information concerning significant accounting policies and acquisitions, respectively.
ITEM 7.
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
On February 25, 2016, the Company's board of directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month period which ends on December 31 or August 31 of each year. The following discussion and analysis was prepared to supplement information contained in the accompanying consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of December 31, 2016, and its results of operations for the years ended December 31, 2016, December 31, 2015 (unaudited), August 31, 2015, and August 31, 2014. It should be read in conjunction with the “Selected Financial Data” and the accompanying audited consolidated financial statements and related notes thereto contained in this Annual Report on Form 10-K. The unaudited results of operations for the year ended December 31, 2015 was derived from data previously reported in the Company's Transition Report on Form 10-K as filed with the SEC on April 22, 2016.
This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the “Cautionary Statement Concerning Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance, and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in “Risk Factors”. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.
Overview
Synergy Resources Corporation is a growth-oriented independent oil and gas company engaged in the acquisition, development, and production of oil and natural gas in the D-J Basin, which we believe to be one of the premier, liquids-rich oil and natural gas resource plays in the United States. It contains hydrocarbon-bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand, and D-Sand. The area has produced oil and natural gas for over fifty years and benefits from established infrastructure including midstream and refining capacity, long reserve life, and multiple service providers.
Our oil and natural gas activities are focused in the Wattenberg Field, predominantly in Weld County, Colorado, an area that covers the western flank of the D-J Basin. Currently, we are focused on the horizontal development of the Codell and Niobrara formations, which are characterized by relatively high liquids content.
In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately 73% of our proved producing reserves, and anticipate operating substantially all of our future net drilling locations. Additionally, our current development plan anticipates that all of our future activities will be concentrated in the Wattenberg Field.
Market Conditions
Market prices for our products significantly impact our revenues, net income, and cash flow. The market prices for oil and natural gas are inherently volatile. To provide historical perspective, the following table presents the average annual NYMEX prices for oil and natural gas for each of the last five years.
For the periods presented in this report, the following table presents the relevant NYMEX price as well as the differential between NYMEX and the wellhead prices realized by us.
Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The negative differential between the prices actually received by us at the wellhead and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments. With regard to the sale of natural gas and liquids, we have historically been able to sell production at prices greater than the prices posted for dry gas, primarily because prices that we receive include payment for a percentage of the value attributable to the natural gas liquids produced with the gas. With the decline in value of NGLs during 2016, we were not able to sell production at prices greater than the prices posted for dry gas.
There has been a significant decline in the price of oil since the summer of 2014; however, oil prices increased in late 2016 from their lows in early 2016. As reflected in published data, the price for WTI oil settled at $37.13 per Bbl on Thursday, December 31, 2015. Comparably, the price of oil settled at $53.75 per Bbl on Friday, December 30, 2016, an increase of 45% from December 31, 2015. Our revenues, results of operations, profitability and future growth, and the carrying value of our oil and gas properties depend primarily on the prices that we receive for our oil and natural gas production.
A decline in oil and natural gas prices will adversely affect our financial condition and results of operations. Furthermore, low oil and natural gas prices can result in an impairment of the value of our properties and the calculation of the “ceiling test” required under the accounting principles for companies following the “full cost” method of accounting. Our ceiling tests resulted in a total impairment charge of $215.2 million for the year ended December 31, 2016, and additional impairments may occur in the future.
Core Operations
The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of December 31, 2016:
In addition to the producing wells summarized in the preceding table, as of December 31, 2016, we were the operator of 49 gross (44 net) wells in progress, which excludes 9 gross (9 net) wells for which we have only set surface casings.
Properties
As of December 31, 2016, our estimated net proved oil and natural gas reserves, as prepared by Ryder Scott, were 38.0 MMBbls of oil and condensate and 331.9 Bcf of natural gas. As of December 31, 2016, we had approximately 397,200 gross and 332,400 net acres under lease. We further delineate our acreage into specific areas, including the areas that we refer to as the Wattenberg Field (approximately 78,500 gross and 68,900 net acres) and the North East Extension Area (approximately 55,300 gross and 27,600 net acres). In addition, we hold approximately 183,600 gross (180,400 net) acres in southwest Nebraska, a conventional oil-prone prospect, and approximately 77,900 gross (54,200 net) acres in other areas of Colorado.
Production
For the year ended December 31, 2016, our average net daily production increased to 11,670 BOED as compared to 9,548 BOED for the year ended December 31, 2015. By comparison, our production increased from 4,290 BOED for the year ended August 31, 2014 to 8,750 BOED for the year ended August 31, 2015.
Significant Business Developments
Acquisitions
In May 2016, the Company entered into an agreement to effect the GC Acquisition, a purchase totaling approximately 72,000 gross (33,100 net) acres located in an area known as the Greeley-Crescent development area in Weld County Colorado, primarily in and around the city of Greeley, for $505 million. Estimated net daily production from the acquired properties was approximately 2,400 BOE at the time of entering into the agreement.
In June 2016, the Company closed on the portion of the assets comprised of the undeveloped lands and non-operated production. The effective date of this part of the transaction was April 1, 2016, and the purchase price was $486.4 million, comprised of $485.1 million in cash and the assumption of certain liabilities. The second closing will cover the operated producing properties and is expected to be completed in 2017. The Company has placed $18.2 million in escrow to be released upon the second closing. For the second closing, the effective date will be April 1, 2016 for the horizontal wells to be acquired and the first day of the calendar month in which the closing for such properties occurs for the vertical wells. The second closing is subject to certain closing conditions, including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all.
During 2016, the Company completed various other acquisitions of undeveloped oil and natural gas leasehold interests in the D-J Basin for a total of $20.7 million in cash and the assumption of certain liabilities or receivables. These acquisitions were completed in an effort to increase our working interests and to extend the lateral lengths of our wells. See Note 3 to the consolidated financial statements included in this report for further discussion.
Divestitures
In April 2016, the Company agreed to divest approximately 3,700 net undeveloped acres primarily in Adams County, Colorado and 107 vertical wells primarily in Weld County, Colorado for total consideration of approximately $24.7 million in cash and the assumption by the buyers of $0.5 million in liabilities. The divested assets had associated production of approximately 200 BOED. The vertical well transaction closed in April 2016, and the undeveloped acreage transaction closed in June 2016.
In January 2017, we executed a purchase and sale agreement with a private party resulting in the divestiture of acreage outside of the Company's core development area. The transaction resulted in the Company divesting approximately 10,000 net undeveloped acres and approximately 700 BOED of associated production for $71 million. The transaction is expected to close in the first quarter of 2017.
Equity Offerings
In January 2016, the Company closed on the sale of 16,100,000 shares of common stock pursuant to an underwriting agreement with Credit Suisse Securities (USA) LLC, acting severally on behalf of itself and the other underwriters. The price to the Company was $5.545 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $89.2 million. Proceeds were used to repay amounts borrowed under the Revolver and for general corporate purposes, which included continuing to develop our acreage position in the Wattenberg Field in Colorado and funding a portion of our 2016 capital expenditure program.
In April 2016, the Company closed on the sale of an additional 22,425,000 shares of common stock pursuant to an underwriting agreement with substantially the same underwriting group. The price to the Company was $7.3535 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $164.8 million. The proceeds of this offering were used for general corporate purposes, including to fund the GC Acquisition.
In May and June 2016, the Company closed on the sale of an additional 51,750,000 shares of common stock pursuant to an underwriting agreement with substantially the same underwriting group. The price to the Company was $5.597 per share and net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $289.4 million. The proceeds of this offering were used for general corporate purposes, including to fund the GC Acquisition.
Revolving Credit Facility
We continue to maintain a borrowing arrangement with our bank syndicate to provide us with liquidity, which could be used to develop oil and gas properties, acquire new oil and gas properties, and for working capital and other general corporate purposes. As of December 31, 2016, this revolving credit facility provides for maximum borrowings of $500 million, subject to adjustments based upon a borrowing base calculation, which is re-determined semi-annually using updated reserve reports. The Revolver is collateralized by certain of our assets, including substantially all of our producing wells and developed oil and gas leases, and bears a variable interest rate on borrowings with the effective rate varying with utilization. The Revolver expires on December 15, 2019. See further discussion in Note 6 to our consolidated financial statements.
In October 2016, the Revolver was amended in connection with the semi-annual redetermination of the borrowing base. The borrowing base was increased from $145 million to $160 million. Due to outstanding letters of credit, approximately $159.5 million of the borrowing base was available to use for future borrowings as of December 31, 2016.
The Revolver contains covenants that, among other things, restrict the payment of dividends and limits our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved reserves as projected in the semi-annual reserve report.
The Revolver also requires the Company to maintain compliance with certain financial and liquidity ratio covenants. Under the requirements, the Company, on a quarterly basis, must not (a) at any time permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; or (b) as of the last day of any fiscal quarter permit its current ratio, as defined in the agreement, to be less than 1.0 to 1.0. As of December 31, 2016, the most recent compliance date, the Company was in compliance with these covenants and expects to remain in compliance throughout the next 12-month period.
Senior Notes
In June 2016, the Company issued $80 million aggregate principal amount of 9% Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Senior Notes accrues at 9% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each year, beginning on December 15, 2016. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. The net proceeds from the sale of the Senior Notes were $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions. The net proceeds were used to fund the GC Acquisition. The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications.
Impairment of Full Cost Pool
Every quarter, we perform a ceiling test as prescribed by SEC regulations for entities following the full cost method of accounting. This test determines a limit on the book value of oil and gas properties using a formula to estimate future net cash flows from oil and natural gas reserves. This formula is dependent on several factors and assumes future oil and natural gas prices to be equal to an unweighted arithmetic average of oil and natural gas prices derived from each of the 12 months prior to the reporting period. During the twelve months ended December 31, 2016, these calculations indicated that the ceiling amount had declined, largely as a result of the decline in oil and natural gas prices, such that the ceiling was less than the net book value of oil and gas properties. As a result of ceiling tests throughout the year, we recorded non-cash ceiling test impairments totaling $215.2 million for the twelve months ended December 31, 2016. As of our December 31, 2016 ceiling test, we determined that
a ceiling test impairment was not necessary. The December 31, 2016 ceiling test used average realized prices of $36.07 per barrel and $2.44 per Mcf as compared to the September 30, 2016 prices of $31.95 per barrel and $2.21 per Mcf, an increase of approximately 13% and 10%, respectively. A full cost ceiling impairment is recognized as a charge to earnings and may not be reversed in future periods, even if oil and natural gas prices subsequently increase. Declining commodity prices, other adverse market conditions, and acquisitions or divestitures could result in further ceiling test write-downs in the future.
Drilling and Completion Operations
Our drilling and completion schedule drives our production forecast and our expected future cash flows. As commodity prices have fallen over the past two years, we have been able to reduce per-well drilling and completion costs. We believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve reasonable well-level rates of return when drilling mid-length or long laterals. Should commodity prices weaken our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If management believes that the well-level internal rate of return will be at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether. Conversely, if commodity prices move higher, we may choose to accelerate drilling and completions activities.
During the twelve months ended December 31, 2016, we drilled 56 operated horizontal wells, completing 24 of them. As of December 31, 2016, we are the operator of 49 gross (44 net) horizontal wells in progress, which excludes 9 gross (9 net) horizontal wells for which we have only set surface casings. For 2017, we expect to drill 102 gross operated horizontal wells of mostly mid-length and long laterals targeting the Codell and Niobrara zones.
In addition, we participated in drilling and completion activities on 3 gross (0.42 net) non-operated horizontal wells during the year. As of December 31, 2016, we are participating in 26 gross (2 net) non-operated horizontal wells in progress.
Other Operations
We continue to be opportunistic with respect to acquisition efforts to increase our working interests and drilling location inventory. Further, in an effort to extend the length of laterals and/or increase working interests in our wells, we continue to enter into land and working interest swaps.
Trends and Outlook
Oil traded at $37.13 per Bbl on December 31, 2015, but has since increased approximately 45% as of December 30, 2016 to $53.75. Natural gas traded at $2.34 per Mcf on December 31, 2015, but increased approximately 59% as of December 30, 2016 to $3.72. Although oil prices have risen in the last six months, oil prices continue to remain significantly lower than their 2014 levels, which were near $100/bbl. Lower oil prices (i) will reduce our cash flow which, in turn, could reduce the funds available for exploring and replacing oil and natural gas reserves, (ii) could potentially reduce our current Revolver borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) could reduce the number of oil and gas prospects which have reasonable economic returns, (iv) may cause us to allow leases to expire based upon the value of potential oil and natural gas reserves in relation to the costs of exploration, (v) may result in marginally productive oil and natural gas wells being abandoned as non-commercial, and (vi) may cause ceiling test impairments.
Other factors that will most significantly affect our results of operations include (i) activities on properties that we operate, (ii) the marketability of our production, (iii) our ability to satisfy our financial and transportation obligations, (iv) completion of acquisitions of additional properties and reserves, and (v) competition from larger companies. Our revenues will also be significantly impacted by our ability to maintain or increase oil or natural gas production through exploration and development activities.
We utilize what we believe to be industry best practices in our effort to achieve optimal hydrocarbon recoveries. Currently, our practice is to drill 16 to 24 horizontal wells per 640-acre section depending upon specific geologic attributes and existing vertical wellbore development. Some operators are testing higher density programs, but it is too early to determine if the recoveries justify the additional capital cost.
The decline in commodity prices since late 2014 has led to a corresponding decline in service costs, which directly relate to our drilling and completion costs. We have been able to reduce drilling and completion costs due to a combination of optimizing well designs, lower contract rates for drilling rigs, fewer average days to drill, and lower completion costs. This focus on cost reduction has supported well-level economics in spite of the severe drop in the prices of oil and natural gas. We continue to strive to reduce drilling and completion costs going forward, but as commodity prices improve and industry activity increases, we may experience higher service costs causing well-level rates of return to be lower.
From time to time, our production has been adversely impacted by high natural gas gathering line pressures. Where it is cost effective, we install wellhead compression to enhance our ability to inject natural gas into the gathering system and, in some instances, install larger gathering lines to help mitigate the impacts. Additionally, midstream companies that operate the gas gathering pipelines in the area continue to make significant capital investments to increase their capacities. While these actions have helped reduce overall line pressures in the field, some of our producing locations have been curtailed on occasion due to line pressures exceeding system limits.
To address natural gas production in the D-J Basin, DCP Midstream has announced plans for multiple projects including new processing plants, low pressure gathering systems, additional compression and plant bypass infrastructure. Most notably, in collaboration with DCP Midstream, we and several other producers have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin. The initial plan includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system, both expected to be completed by late 2018. Additionally, through the same framework, all of the parties are working to form a cooperative development plan to add another 200 MMcf/d plant by mid-2019.
We have extended the use of oil gathering lines to certain production locations. These gathering systems are owned and operated by independent third parties, and we commit specific wells to these systems. We believe that oil gathering lines have several benefits including, a) reduced need to use trucks to gather our oil, thereby reducing truck traffic in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) reduced on-site oil storage capacity, resulting in lower production location facility costs, and d) generally less noise and dust.
Oil transportation and takeaway capacity has increased with the expansion of certain interstate pipelines servicing the Wattenberg Field. This has reversed the prior imbalance of oil production exceeding the combination of local refinery demand and the capacity of pipelines to move the oil to other markets. Depending on transportation commitments, local refinery demand, and our production volumes, we may be able to reduce the negative differential that we have historically realized on our oil production. Further details regarding posted prices and average realized prices are discussed in "-Market Conditions."
As of December 31, 2016, we have identified over 1,000 gross mid- to long-lateral (~7,500’ to ~9,500’) drilling locations across our acreage position. For 2017, we expect to drill 102 gross operated horizontal wells of mostly mid-length and long laterals targeting the Codell and Niobrara zones. We anticipate this drilling and completion schedule will cost between $260 million and $300 million and will lead to a significant increase in production and associated proved developed producing reserves while allowing us to retain significant operational and financial flexibility to reduce or accelerate activity in response to changing economic conditions. Initial estimates place full-year 2017 production between 17,500 BOED and 20,000 BOED.
Other than the foregoing, we do not know of any trends, events, or uncertainties that will have had or are reasonably expected to have a material impact on our sales, revenues, expenses, liquidity, or capital resources.
Results of Operations
Material changes of certain items in our consolidated statements of operations included in our consolidated financial statements for the periods presented are discussed below. All references to the year ended December 31, 2015 are unaudited.
For the year ended December 31, 2016 compared to the year ended December 31, 2015
For the year ended December 31, 2016, we reported net loss of $219.2 million compared to net loss of $131.7 million during the year ended December 31, 2015. Net loss per basic and diluted share was $(1.26) for the year ended December 31, 2016 compared to net loss per share per basic and diluted share of $(1.27) for the year ended December 31, 2015. Revenues increased slightly during the year ended December 31, 2016 compared to the year ended December 31, 2015. As of December 31, 2016, we had 631 gross producing wells, compared to 609 gross producing wells as of December 31, 2015. The impact of changing prices on our commodity derivative positions also drove significant differences in our results of operations between the two periods.
Oil and Natural Gas Production and Revenues - For the year ended December 31, 2016, we recorded total oil and natural gas revenues of $107.1 million compared to $106.1 million for the year ended December 31, 2015. The following table summarizes key production and revenue statistics:
Net oil and natural gas production for the year ended December 31, 2016 averaged 11,670 BOED, an increase of 22% over average production of 9,548 BOED in the year ended December 31, 2015. From December 31, 2015 to December 31, 2016, our well count increased by 25 net horizontal wells, growing our reserves and daily production totals. The 18% decline in average sales prices offset the effects of increased production, resulting in relatively flat revenues overall.
LOE - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells in production and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of oil and natural gas. During the year ended December 31, 2016, we experienced increased production expense primarily due to operating additional horizontal wells, increased production, and an increase in regulatory compliance projects.
Production taxes - Taxes tend to increase or decrease primarily based on the value of oil and natural gas sold. During the year ended December 31, 2016, production taxes were $5.7 million, or $1.34 per BOE, compared to $9.4 million, or $2.70 per BOE, during the prior year comparable period. As a percent of revenues, taxes were 5.3% and 8.9% for the years ended December 31, 2016 and 2015, respectively. The decrease in 2016 is due to a change in estimate for production taxes based on recent historical experience and additional information received during the period. Based on this analysis, our production tax accrual was reduced, resulting in an approximate $3.6 million reduction to our production taxes.
DD&A - The following table summarizes the components of DD&A:
For the year ended December 31, 2016, depletion of oil and gas properties was $10.93 per BOE compared to $17.81 per BOE for the year ended December 31, 2015. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. This ratio was significantly reduced due to the impairments of our full cost pool, which primarily occurred during the second half of calendar 2015 and the first half of 2016, and the increase in our total proved reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning of quarter estimated total reserves determines the depletion rate.
Full cost ceiling impairment - During the year ended December 31, 2016, we recognized an impairment of $215.2 million as compared to an impairment of $141.2 million for the year ended December 31, 2015, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See “-Critical Accounting Policies-Oil and Gas Properties, including Ceiling Test.”
General and Administrative (“G&A”) - The following table summarizes G&A expenses incurred and capitalized during the periods presented:
G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. During the year ended December 31, 2016, we increased our employee count from 62 as of December 31, 2015 to 96, while reducing the number of consultants, advisors, and contractors that had historically been used for certain tasks. Additionally, during the year ended December 31, 2015, we awarded bonuses, consisting of cash and restricted stock, to management, employees, and directors. Most significantly, bonuses totaling approximately $4.8 million (including restricted stock valued at $4.0 million) were paid to our former co-CEOs, both of whom resigned as of December 31, 2015.
Our G&A expense for the year ended December 31, 2016 includes stock-based compensation of $9.5 million compared to $14.7 million for the year ended December 31, 2015. Stock-based compensation is a non-cash charge that is based on the calculated fair value of stock options, performance stock units, restricted share units, and stock bonus shares that we grant for compensatory purposes. For stock options, the fair value is estimated using the Black-Scholes-Merton option pricing model. For performance stock units, the fair value is estimated using the Monte Carlo model. For restricted stock units and stock bonus shares, the fair value is estimated using the closing stock price on the grant date. Amounts are pro-rated over the vesting terms of the award agreements, which are generally three to five years.
Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the year ended December 31, 2015 to the year ended December 31, 2016 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.
Commodity derivative gains (losses) - As more fully described in “-Liquidity and Capital Resources-Oil and Gas Commodity Contracts,” we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the year ended December 31, 2016, we realized a cash settlement gain of $2.4 million, net of previously incurred premiums attributable to the settled commodity contracts. In 2015, we realized a cash settlement gain of $28.4 million.
In addition, for the year ended December 31, 2016, we recorded an unrealized loss of $10.1 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the year ended December 31, 2015, we reported an unrealized loss of $17.3 million. Unrealized losses are non-cash items.
Income taxes - We reported income tax expense of $0.1 million for the year ended December 31, 2016, calculated at an effective tax rate of 0%. In 2015, we reported income tax benefit of $14.1 million, calculated at an effective tax rate of 10%. As explained in more detail below, during the year ended December 31, 2016, the effective tax rate was substantially reduced by the recognition of a full valuation allowance on the net deferred tax asset.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. Based on the level of losses in the current period and the level of uncertainty with respect to future taxable income over the period in which the deferred tax assets are deductible, a valuation allowance has been provided as of December 31, 2016. During 2015, we reached the same conclusion; therefore, a valuation allowance has been provided as of December 31, 2015.
For the year ended August 31, 2015, compared to the year ended August 31, 2014
For the year ended August 31, 2015, we reported net income of $18.0 million compared to net income of $28.9 million during the year ended August 31, 2014. Net income per basic and diluted share were $0.19 and $0.19, respectively, for the year ended August 31, 2015 compared to earnings per share of $0.38 and $0.37 per basic and diluted share, respectively, for the year ended August 31, 2014. Revenues increased $20.6 million during the year ended August 31, 2015 compared to the year ended August 31, 2014 due to rapid growth in production as discussed below. As of August 31, 2015, we had 582 gross producing wells, compared to 404 gross producing wells as of August 31, 2014. However, although our production more than doubled during the comparable periods, our revenues during the year ended August 31, 2015 increased only 20% as a result of declining oil and natural gas prices. The impact of changing prices on our commodity derivative positions also drove significant differences in our results of operations between the two periods.
Oil and Natural Gas Production and Revenues - For the year ended August 31, 2015, we recorded total oil and natural gas revenues of $124.8 million compared to $104.2 million for the year ended August 31, 2014, an increase of $20.6 million or 20%. The following table summarizes key production and revenue statistics:
Net oil and natural gas production for the year ended August 31, 2015 averaged 8,750 BOED, an increase of 104% over average production of 4,290 BOED in the year ended August 31, 2014. Year over year, we added 48 net horizontal wells, including 3 net horizontal wells acquired, increasing our reserves, producing wells, and daily production totals. The decline in average sales prices by approximately 41% mostly offset the effects of increased production, resulting in an overall 20% increase of revenues.
LOE - Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
Lease operating and workover costs tend to increase or decrease primarily in relation to the number of wells in production and, to a lesser extent, on fluctuation in oil field service costs and changes in the production mix of oil and natural gas. During the year ended August 31, 2015, we experienced decreased production costs per BOE primarily as a result of increased production. Partially offsetting this decline in costs was increased costs resulting from intermittent midstream restrictions that reduced the efficiency and capacity of the gas gathering system.
Production taxes - During the year ended August 31, 2015, production taxes were $11.3 million, or $3.55 per BOE, compared to $9.7 million, or $6.17 per BOE, during the prior year. Taxes tend to increase or decrease primarily based on the value of oil and natural gas sold. As a percent of revenues, taxes were 9.1% and 9.3% for the years ended August 31, 2015 and 2014, respectively.
DD&A - The following table summarizes the components of DD&A:
For the year ended August 31, 2015, depletion of oil and gas properties was $20.62 per BOE compared to $21.05 per BOE for the year ended August 31, 2014. The decrease in the DD&A rate was the result of a decrease in the ratio of total costs capitalized in the full cost pool to the estimated recoverable reserves. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, wherein the ratio of production volumes for the quarter to beginning-of-quarter estimated total reserves determine the depletion rate. Since DD&A expense represents depletion of historical costs, our implemented reductions in well costs were not fully reflected in the rate.
Full cost ceiling impairment - During the year ended August 31, 2015, we recognized a total impairment of $16.0 million, representing the amount by which the net capitalized costs of our oil and gas properties exceeded our full cost ceiling. See “-Critical Accounting Policies-Oil and Gas Properties, including Ceiling Test.”
G&A - The following table summarizes G&A expenses incurred and capitalized during the periods presented:
G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. In an effort to minimize overhead costs, we employed a total staff of 36 employees as of August 31, 2015 and used consultants, advisors, and contractors to perform certain tasks when we considered it to be cost effective.
Although G&A costs increased as we grew the business, we strove to maintain an efficient overhead structure. For the year ended August 31, 2015, G&A was $5.95 per BOE compared to $6.48 per BOE for the year ended August 31, 2014.
Our G&A expense for the year ended August 31, 2015 includes stock-based compensation of $7.7 million compared to $3.0 million for the year ended August 31, 2014.
Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the development of properties. Those costs were reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from 2014 to 2015 reflected our increasing activities to acquire leases and develop the properties.
Commodity derivative gains (losses) - As more fully described in “-Liquidity and Capital Resources-Oil and Gas Commodity Contracts,” we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the year ended August 31, 2015, we realized a cash settlement gain of $30.5 million, including gains of $10.0 million from the settlement of contracts at their scheduled maturity dates and gains of $20.5 million from the early liquidation of “in-the-money” contracts. For the prior year, we realized a cash settlement loss of $2.1 million.
In addition, for the year ended August 31, 2015, we recorded an unrealized gain of $1.8 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the year ended August 31, 2014, we reported an unrealized gain of $2.5 million. Unrealized gains are non-cash items.
Income taxes - We reported income tax expense of $11.7 million for the year ended August 31, 2015, calculated at an effective tax rate of 39%. During the comparable prior year period, we reported income tax expense of $15.0 million, calculated at an effective tax rate of 34%. For both periods, it appeared that the tax liability would be substantially deferred into future years. During both periods, the effective tax rate differed from the federal and state statutory rate primarily due to the impact of deductions for percentage depletion.
Each year, management evaluates all the positive and negative evidence regarding our tax position and reaches a conclusion on the most likely outcome. As of August 31, 2015 and 2014, we concluded that it was more likely than not that we would be able to realize a benefit from the net operating loss carryforward and, therefore, included it in our inventory of deferred tax assets.
Liquidity and Capital Resources
Historically, our primary sources of capital have been net cash provided by the sale of equity and debt securities, cash flow from operations, proceeds from the sale of properties, and borrowings under bank credit facilities. Our primary use of capital has been for the exploration, development, and acquisition of oil and gas properties. Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us.
We believe that our capital resources, including cash on hand, the previously announced sale of non-core assets totaling $71 million (subject to certain closing conditions), amounts available under our revolving credit facility, and cash flow from operating activities will be sufficient to fund our planned capital expenditures and operating expenses for the next twelve months. We funded the purchase price of the GC Acquisition through a combination of cash on hand and proceeds of financing transactions, including the issuance of the Senior Notes. To the extent actual operating results differ from our anticipated results, available borrowings under our credit facility are reduced, or we experience other unfavorable events, our liquidity could be adversely impacted. Our liquidity would also be affected if we increase our capital expenditures or complete one or more additional acquisitions. Terms of future financings may be unfavorable, and we cannot assure investors that funding will be available on acceptable terms.
As operator of the majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled. This allows us to modify our capital spending as our financial resources allow and market conditions support. Additionally, our relatively low utilization of debt enhances our financial flexibility as it provides a potential source of future liquidity while currently not overly burdening us with restrictive financial covenants and mandatory repayment schedules.
Sources and Uses
Our sources and uses of capital are heavily influenced by the prices that we receive for our production. During the twelve months ended December 31, 2016, the NYMEX-WTI oil price ranged from a low of $26.19 per Bbl on February 11, 2016 to a high of $54.01 per Bbl on December 28, 2016, while the NYMEX-Henry Hub natural gas price ranged from a low of $1.64 per MMBtu on March 3, 2016 to a high of $3.93 per MMBtu on December 28, 2016. These markets will likely continue to be volatile in the future. To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments. This enables us to accelerate or decelerate our activities quickly in response to changing industry environments.
At December 31, 2016, we had cash and cash equivalents of $18.6 million, $80 million outstanding on our Senior Notes, and no balance outstanding under our revolving credit facility. Our sources and (uses) of funds for the twelve months ended December 31, 2016 and 2015 and the twelve months ended August 31, 2015 and 2014 are summarized below (in thousands):
Net cash provided by operating activities was $48.7 million and $103.8 million for the twelve months ended December 31, 2016 and 2015, respectively, and $125.1 million and $74.9 million for the years ended August 31, 2015 and 2014, respectively. The decline in cash from operating activities over the periods reflects the decline in commodity prices, partially offset by the increase in production.
During the twelve months ended December 31, 2016, we received cash proceeds from the following financing activities which were used to repay amounts borrowed under the Revolver, for general corporate purposes (which included continuing to develop our acreage position in the Wattenberg Field) and paying for the purchase price for the GC Acquisition:
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In January 2016, we received cash proceeds of approximately $89.2 million (after underwriting discounts, commissions and expenses) from our public offering of 16,100,000 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of $5.545 per share.
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In January 2016, the Company repaid its outstanding borrowings under the Revolver of $78 million. In addition, in June 2016, the Company borrowed approximately $55 million under the Revolver. The full amount borrowed was also repaid in June 2016.
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In April 2016, we received cash proceeds of approximately $164.8 million (after underwriting discounts, commissions and expenses) from our public offering of 22,425,000 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of $7.3535 per share.
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In April 2016, the Company agreed to divest approximately 3,700 net undeveloped acres and 107 vertical wells primarily in Adams County, Colorado for total consideration of approximately $24.7 million in cash and the assumption by the buyers of $0.5 million in liabilities.
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In May and June 2016, we received cash proceeds of approximately $289.4 million (after underwriting discounts, commissions and expenses) from our public offering of 51,750,000 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of $5.597 per share.
•
In June 2016, the Company issued $80 million aggregate principal amount of Senior Notes in a private placement to qualified institutional buyers. See "- Senior Notes." The net proceeds from the sale of the Senior Notes were $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions.
Credit Facility
We maintain a borrowing arrangement with a banking syndicate with a maturity date of December 15, 2019. The arrangement, in the form of a revolving credit facility, was most recently amended with the Ninth Amendment to the credit facility in October 2016. The arrangement provides for a maximum loan commitment of $500 million; however, the maximum amount that we can borrow at any one time is subject to a borrowing base limitation, which stipulates that we may borrow up to the lesser of the maximum loan commitment or the borrowing base. The borrowing base can increase or decrease based upon the value of the collateral, which secures any amounts borrowed under the line of credit. The value of the collateral will generally be derived with reference to the estimated future net cash flows from our proved oil and natural gas reserves, discounted by 10%. Amounts borrowed under the facility are secured by certain of our assets, including substantially all of our producing wells and developed oil and gas leases
The borrowing base was increased to $160 million on October 14, 2016. As of December 31, 2016, there was no outstanding principal balance, $0.5 million in letters of credit was applied against the Revolver, and $159.5 million was available to us for future borrowings. The next semi-annual redetermination of the borrowing base has been scheduled for May 2017. Interest on our revolving line of credit accrues at a variable rate. The interest rate pricing grid contains a graduated escalation in applicable margin for increased utilization.
The Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. Under the requirements, the Company, on a quarterly basis, must not (a) at any time permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; or (b) as of the last day of any fiscal quarter permit its current ratio, as defined in the agreement, to be less than 1.0 to 1.0.
Senior Notes
In June 2016, the Company issued $80 million aggregate principal amount of the Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Senior Notes accrues at 9% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each year, beginning on December 15, 2016. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes subject to the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest. On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at the redemption price equal to a specified percentage of the principal amount of the redeemed notes (104.50% for 2018, 102.25% for 2019, and 100% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.
The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications.
Capital Expenditures
Capital expenditures for oil and natural gas activities totaled $667.6 million and $241.7 million for the twelve months ended December 31, 2016 and 2015, respectively, and $304.9 million and $207.8 million for the years ended August 31, 2015 and 2014, respectively. The following table summarizes our capital expenditures for oil and gas properties (in thousands):
*Capital expenditures reported in the consolidated statement of cash flows are calculated on a cash basis, which differs from the accrual basis used to calculate the capital expenditures.
Excluding the GC Acquisition, the majority of capital expenditures during the twelve months ended December 31, 2016 were associated with the costs of drilling and completing wells. During the twelve months ended December 31, 2016, we drilled 56 operated horizontal wells, completing 24 of them. As of December 31, 2016, we are the operator of 49 gross (44 net) horizontal wells in progress, which excludes 9 gross (9 net) horizontal wells for which we have only set surface casings. All of the wells in progress at December 31, 2016 are scheduled to commence production before December 31, 2017.
In addition, we participated in drilling and completion activities on 3 gross (0.42 net) non-operated horizontal wells during the year. As of December 31, 2016, we are participating in 26 gross (2 net) non-operated horizontal wells in progress.
Capital Requirements
Our level of exploration, development, and acreage expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows, and development results, among other factors. Our primary need for capital will be to fund our anticipated drilling and completion activities, and any other acquisitions that we may complete during the year ending December 31, 2017.
After completing the GC Acquisition in mid-2016, we set our preliminary 2017 drilling and completion capital program between $260 million and $300 million. However, as commodity prices have improved, we expect to continuously operate two drilling rigs, which would put our capital program on the high side of the earlier announced expenditures. Should commodity prices and/or economic conditions change, we can reduce or accelerate our drilling and completion activities, which could have a material impact on our anticipated capital requirements.
For the near term, we believe that we have sufficient liquidity to fund our needs through cash on hand, cash flow from operations, and additional borrowings available under our revolving credit facility. In contemplating our planned 2017 capital program, we expect the borrowing base under our revolving credit facility to increase due to the anticipated significant growth in our production and associated proved developed producing reserves. However, should this not occur and/or to meet all of our long-term goals, we may need to raise additional funds to drill new wells through the sale of our securities, from third parties willing to pay our share of drilling and completing wells, or from other sources. We may not be successful in raising the capital needed to drill or acquire oil or natural gas wells.
Oil and Gas Commodity Contracts
We use derivative contracts to help protect against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and natural gas production. At January 31, 2017, we had open positions covering 1.7 million barrels of oil and 8,442 MMcf of natural gas. We do not use derivative instruments for speculative purposes.
Our commodity derivative instruments may include but are not limited to “collars,” “swaps,” and “put” positions. Our derivative strategy, including the volumes and commodities covered and the relevant strike prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in our credit facility.
A “put” option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, purchase put options, which require us to pay premiums at the time that we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase. The ownership of put options is consistent with our derivative strategy inasmuch as the value of the puts will increase as commodity prices decline, helping to offset the cash flow impact of a decline in realized prices for the underlying commodity. However, if the underlying commodity increases in value, there is a risk that the put option will expire worthless, in which case the net premiums paid would be recognized as a loss.
Conversely, a “call” option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create “collars”. We regularly utilize “no premium” (a.k.a. zero cost) collars constructed by selling call options while simultaneously buying put options, in which the premiums paid for the puts is offset by the premiums received for the calls. Collars are consistent with our derivative strategy inasmuch as they establish a known range of prices to be received for the associated volume equivalents, being bound at the upper end by the call’s strike price (the “ceiling”) and at the lower end by the put’s strike price (the “floor”).
Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term. Swaps are consistent with our derivative strategy inasmuch as they establish a known future price to be received for the associated equivalent volumes.
During periods of significant price declines, for settled contracts structured as “collars,” we will receive settlement payments from the contracts’ counterparties for the difference between the contracted “floor” price and the average posted price for the contract period. For settled “swaps,” we will receive the difference between the contracted swap price and the average posted price for the contract period, if lower. For settled “put” contracts, we will receive the difference between the put’s strike price and the average posted price for the contract period. If we decide to liquidate an “in-the-money” position prior to settlement date, we will receive the approximate fair value of the contract at that time. These realized gains increase our cash flows for the period in which they are recognized.
Conversely, during periods of significant price increases, upon settlement we would be obligated to pay the counterparties the difference between the contract’s “ceiling” and/or swap price and the average posted price for the contract period. If liquidated prior to settlement, we would pay the approximate fair market value to close the position at that time. These realized losses decrease our cash flows for the period in which they are recognized. Losses associated with puts that expire out-of-the-money are simply the original premium paid for the contract and are recognized upon expiration.
The fair values of our open, but not yet settled, derivative contracts are estimated by obtaining independent market quotes as well as using industry standard models that consider various assumptions including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. We compare the valuations calculated by us to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or us, as appropriate.
The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will also impact our net income in the period recorded.
We do not designate our commodity contracts as accounting hedges. Accordingly, we use mark-to-market accounting to value the portfolio at the end of each reporting period. Mark-to-market accounting can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility in the past and are likely to experience it in the future. Mark-to-market accounting treatment results in volatility of our results as unrealized gains and losses from derivatives are reported. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues.
During the year ended December 31, 2016, we reported an unrealized commodity activity loss of $10.1 million. Unrealized losses are non-cash items. We also reported a realized gain of $2.4 million, representing the cash settlement of commodity contracts settled during the period, net of previously incurred premiums attributable to the settled commodity contracts.
At December 31, 2016, we estimated that the fair value of our various commodity derivative contracts was a net liability of $2.6 million. See Note 8, Commodity Derivative Instruments, to the accompanying consolidated financial statements included elsewhere in this report for further details of our derivative contracts outstanding at December 31, 2016.
Contractual Commitments
The following table summarizes our contractual obligations as of December 31, 2016 (in thousands):
Represents an estimate of the commitment related to the use of one rig. Actual amounts will vary as a result of a number of variables, including target formations, measured depth, and other technical details.
We have entered into agreements that require us to deliver minimum amounts of oil to certain third parties through 2021. Production can be sourced via third party contract, in-kind agreements, or self-sustained production. We will incur a charge of approximately $5.62 per Bbl if a minimum quantity of oil is not delivered to the pipeline-related counterparties. Amounts reflect the estimated deficiency payments under our pipeline-related commitments assuming no deliveries are made. Potential damages and other charges related to nonperformance under these contracts are not included in the amounts above. See further discussion in Note 16 to our consolidated financial statements.
In collaboration with several other producers and DCP Midstream, we have entered into an agreement that requires us to deliver minimum amounts of natural gas under certain circumstances. Our share of the commitment would require
46.4 MMcf of natural gas per day for a period of 7 years from the plant in-service date, which is currently expected to be in late 2018. We may be required to pay penalties or damages pursuant to this agreement if we are unable to fulfill our contractual obligation from our own production and if the collective volumes delivered by other producers in the D-J Basin are not in excess of the total commitment. At this time, we are unable to reasonably estimate these amounts, and they have therefore not been reflected in the table above. See further discussion in Note 16 to our consolidated financial statements.
Includes interest payments related to the issuance of the Senior Notes in June 2016. See further discussion in Note 7 to our consolidated financial statements.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on our financial condition, changes in financial condition, revenues or expense, results of operations, liquidity, or capital resources.
Non-GAAP Financial Measures
In addition to financial measures presented on the basis of accounting principles generally accepted in the United States of America ("US GAAP"), we present certain financial measures which are not prescribed by US GAAP ("non-GAAP"). A summary of these measures is described below.
Adjusted EBITDA
We use "adjusted EBITDA," a non-GAAP financial measure, for internal managerial purposes because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed in the table below from net loss in arriving at adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures, and the method by which the assets were acquired. This measure is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing, or financing activities, and it should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with US GAAP. Our definition of adjusted EBITDA may not be comparable to measures with similar titles reported by other companies. We believe that adjusted EBITDA is a widely used in our industry as a measure of operating performance and may also be used by investors to measure our ability to meet debt covenant requirements. We define adjusted EBITDA as net income (loss) adjusted to exclude the impact of the items set forth in the table below.
PV-10
PV-10 is a non-GAAP financial measure. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with US GAAP, but rather should be considered in addition to the standardized measure.
PV-10 is derived from the standardized measure, which is the most directly comparable GAAP financial measure. PV-10 is calculated using the same inputs and assumptions as the standardized measure, with the exception that it omits the impact of future income taxes. It is considered to be a pre-tax measurement.
The following table provides a reconciliation of the standardized measure to PV-10 at December 31, 2016 and 2015 and August 31, 2015 and 2014 (in thousands):
Critical Accounting Policies
We prepare our consolidated financial statements and the accompanying notes in conformity with US GAAP, which requires management to make estimates and assumptions about future events that affect the reported amounts in the consolidated financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management discusses the development, selection, and disclosure of each of the critical accounting policies.
Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Numerous assumptions are used in the reserve estimation process. Various engineering and geologic criteria are interpreted to derive volumetric estimates, and financial assumptions are made with regard to realized pricing, costs to be incurred to develop and operate the properties, and future tax regimes.
In spite of the imprecise nature of reserves estimates, they are a critical component of our consolidated financial statements. The determination of the depletion component of our DD&A, as well as the ceiling test calculation, is highly dependent on estimates of proved oil and natural gas reserves. For example, if estimates of proved reserves decline, our DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves may result from a number of factors including lower prices, evaluation of additional operating history, mechanical problems on our wells, and catastrophic events. Lower prices can also make it uneconomical to drill wells or produce from properties with high operating costs.
Oil and Gas Properties, including Ceiling Test: There are two alternative methods of accounting for enterprises involved in the oil and gas industry: the successful efforts method and the full cost method. We use the full cost method of accounting. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of dry holes, abandoned leases, delay rentals, and overhead costs directly related to acquisition, exploration, and development activities) are capitalized into a single full cost pool.
Under the successful efforts method, exploration costs, including the cost of exploratory wells that do not increase proved reserves, the cost of geological and geophysical activities, seismic costs, and lease rentals, are charged to expense as incurred. Depletion of oil and gas properties and the evaluation for impairment are generally calculated on a narrowly defined asset basis
compared to an aggregated "pool" basis under the full cost method. The conveyance or abandonment of oil and gas assets generally results in recognition of gain or loss. In comparison, the conveyance or abandonment of full cost properties does not generally result in the recognition of gain or loss unless non-recognition of such a gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves. Under full cost accounting, recognition of gain or loss is only allowable when the transaction would significantly alter the relationship between capitalized costs and proved reserves.
Our calculation of DD&A expense incorporates all the costs capitalized under full cost accounting plus the estimate of costs to be incurred to develop proved reserves. The sum of historical and future costs is allocated to our estimated quantities of proved oil and natural gas reserves and depleted using the units-of-production method. Changes in commodity prices, as well as associated changes in costs that are affected by commodity prices, can have a significant impact on the estimates used in our calculations.
Companies that use full cost accounting perform a ceiling test each quarter. The full cost ceiling test is the impairment test prescribed by SEC Regulation S-X Rule 4-10. The test compares capitalized costs in the full cost pool less accumulated DD&A and related deferred income taxes to a calculated ceiling amount. The calculated ceiling amount is equal to the sum of the present value of estimated future net revenues, plus the cost of properties not being amortized plus the lower of cost or estimated fair value of unproven properties included in costs being amortized less the income tax effects related to differences between the book and tax basis of the properties. The present value of estimated future net revenues is computed by applying current prices of oil and natural gas reserves (as defined in the SEC rules) to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance sheet are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. In accordance with SEC Staff Accounting Bulletin Topic 12D, the income tax effect is calculated by using the present value of estimated future net revenue as pre-tax income, deducting the aforementioned tax effects, and applying the statutory tax rate. If the net capitalized costs exceed the ceiling amount, the excess must be charged to expense in recognition of the impairment.
Under the ceiling test, the estimate of future revenues is calculated using a current price (as defined in the SEC rules to include data points over a trailing 12-month period). Thus, the full impact of a sudden price decline is not recognized immediately. As prices decline, the economic performance of certain properties in the reserve estimate may deteriorate to the point that they are removed from the proved reserve category, thus reducing the quantity and value of proved reserves. The use of a 12-month average will tend to spread the impact of the change on the financial statements over several reporting periods.
During the year ended December 31, 2016, our ceiling tests resulted in a cumulative impairment of $215.2 million, which was driven by the previously discussed declines in the prices of oil and natural gas. A further decline in oil and natural gas prices, or an increase in oil and natural gas prices that is insufficient to overcome the impact of price declines in the year-ago periods on the ceiling test calculation, could result in additional ceiling test impairments in future periods.
Oil and Natural Gas Sales: Our proportionate interests in transactions are recorded as revenue when products are delivered to the purchasers. This method can require estimates of volumes, ownership interests, and settlement prices. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement. Historically, such differences have not been material. During periods of increased price volatility, it will be more difficult to estimate final settlement prices, and retroactive price adjustments pertaining to prior periods could become significant.
Asset Retirement Obligations ("ARO"): We are subject to legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service. Calculation of an ARO requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using our credit-adjusted risk-free rate. Estimates are periodically reviewed and adjusted to reflect changes.
The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made. This is typically when a well is completed, or an asset is placed in service. When the ARO is initially recorded, we capitalize the cost (asset retirement cost or “ARC”) by increasing the carrying value of the related asset. ARCs related to wells are capitalized to the full cost pool and subject to depletion. Over time, the liability increases for the change in its present value (accretion of ARO), while the capitalized cost decreases over the useful life of the asset as depletion expense is recognized.
Commodity Derivative Instruments: Our use of commodity derivative instruments helps us mitigate the cash flow impact of short-term commodity price volatility. We typically enter into contracts covering a portion of our expected oil and natural gas
production over 24 months. We record realized gains and losses for contracts that settle during the reporting periods. Contracts either settle at their scheduled maturity date or settle prior to their scheduled maturity date as a result of our decision to early liquidate an open position. Realized gains and losses represent cash transactions. Under our commodity derivative strategy, we typically receive cash payments when the posted price for the settlement period is less than the derivative price. Conversely, when the posted price for the settlement period is greater than the derivative price, we typically disburse a cash payment to the counterparty. Thus, realized gains and losses tend to offset increases or decreases in our revenue stream that are caused by changing prices.
In comparison, unrealized gains and losses are related to positions that have not yet settled and do not represent cash transactions. At each reporting date, we estimate the fair value of the open (not settled) commodity contract positions and record a gain or loss based upon the change in fair value since the previous reporting date. The fair values are an approximation of the contracts' values as if we sold them on the reporting date. Since these amounts represent a calculated value for a hypothetical transaction, the actual value realized at the cash settlement date may be significantly different.
A downward trend in commodity prices would generally be expected to result in reduced oil and natural gas revenues partially offset realized gains in our hedge transactions. During any reporting period in which the commodity prices decline, we expect to report unrealized gains on our open commodity derivative contracts. However, during any period in which the downward trend reverses, we expect to report unrealized losses. Looking forward, we expect current contracts to be settled or liquidated over the next 24 months. We expect to periodically enter into new commodity derivative contracts at then-current prices. Newer commodity derivative contracts at lower prices will reduce the amount of potential price protection provided by the newer contracts.
Business Combinations: The Company accounts for certain transactions under Accounting Standards Codification ("ASC") 805, Business Combinations. For each transaction, the Company reviews the transaction to determine whether it involves an asset or a business. This review requires that we assess various criteria outlined by ASC 805. If the criteria are not met, the transaction is considered an asset acquisition. If the criteria are met, the transaction is considered an acquisition of a business which the Company accounts for using the acquisition method. Under the acquisition method, assets acquired and liabilities assumed are measured at their fair values, which requires the use of significant judgment since some of the acquired assets and liabilities do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices (when available), appraisals, comparisons to transactions for similar assets and liabilities, and present values of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.
Once the fair values of the assets acquired and the liabilities assumed are determined, the excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, the excess, if any, of the fair value of assets acquired and liabilities assumed over the purchase price of the acquired entity is recognized immediately in earnings as a gain from bargain purchase.
Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination. Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required two-step impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must perform the first step of the two-step impairment test and calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, there is an indication that impairment may exist, and the second step must be performed to measure the amount of impairment loss. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the goodwill exceeds the implied fair value of the goodwill. As a result of declining oil prices, the Company performed an interim goodwill test as of March 31, 2016. We also performed our annual goodwill impairment test as of October 1, 2016. Neither of these tests resulted in an impairment. For both tests, the Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time and contain considerable management judgments. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period.
Income Taxes: Deferred income taxes are recorded for timing differences between items of income or expense reported in the consolidated financial statements and those reported for income tax purposes using the asset/liability method of accounting for income taxes. Deferred income taxes and tax benefits are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and for tax loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be recovered or settled. We provide for deferred taxes for the estimated future tax effects attributable to temporary differences and carryforwards when realization is more likely than not. If we conclude that it is more likely than not that some portion, or all, of the net deferred tax asset will not be realized, the balance of net deferred tax assets is reduced by a valuation allowance.
We consider many factors in our evaluation of deferred tax assets, including the following sources of taxable income that may be available under the tax law to realize a portion or all of a tax benefit for deductible timing differences and carryforwards:
•Future reversals of existing taxable temporary differences,
•Taxable income in prior carry back years, if permitted,
•Tax planning strategies, and
•Future taxable income exclusive of reversing temporary differences and carryforwards.
Recently Adopted and Issued Accounting Pronouncements
See Note 1, Organization and Summary of Significant Accounting Policies, to the accompanying consolidated financial statements included elsewhere in this report for information regarding recently adopted and issued accounting pronouncements.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
Commodity Price Risk - Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. The volatility of oil prices affects our results to a greater degree than the volatility of natural gas prices, as approximately 73% of our revenue during year ended December 31, 2016 was from the sale of oil. A $10.00 per barrel change in our realized oil price would have resulted in a $22.6 million change in revenues for the year ended December 31, 2016, while a $0.50 per Mcf change in our realized natural gas price would have resulted in a $6.0 million change in our natural gas revenues for the year ended December 31, 2016.
During the year ended December 31, 2016, the price of oil and natural gas fluctuated significantly. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the levels of demand and supply for oil (in global or local markets), the establishment of and compliance with production quotas by oil exporting countries, weather conditions which influence the demand for natural gas, the price and availability of alternative fuels, the strength of the US dollar compared to other currencies, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations, and capital resources.
We attempt to mitigate fluctuations in short-term cash flow resulting from changes in commodity prices by entering into derivative positions on a portion of our expected oil and natural gas production. We use derivative contracts to cover up to 85% of expected proved developed producing production as projected in our semi-annual reserve report, generally over a period of two years. We do not enter into derivative contracts for speculative or trading purposes. As of December 31, 2016, we had open oil and natural gas derivatives in a net liability position with a fair value of $2.6 million. A hypothetical upward shift of 10% in the NYMEX forward curve of oil and natural gas prices would decrease the fair value of our position by $1.6 million. A hypothetical downward shift of 10% in the NYMEX forward curve of oil and natural gas prices would increase the fair value of our position by $2.0 million.
Interest Rate Risk - At December 31, 2016, we had no debt outstanding under our bank credit facility. Interest on our credit facility accrues at a variable rate based upon either the Prime Rate or the London InterBank Offered Rate (“LIBOR”) plus an applicable margin. During the year ended December 31, 2016, we incurred interest at a rate of 2.625%. We are exposed to interest rate risk on the bank credit facility if the variable reference rates increase. Historically, a decrease in interest rates would not have a significant impact on us, as the bank credit facility had a minimum interest rate of 2.5%. As of January 28, 2016, the minimum interest rate was removed from the credit facility. If interest rates increase, our monthly interest payments would increase and our available cash flow would decrease. We estimate that if market interest rates increased or decreased by 1%, our interest payments in the year ended December 31, 2016 would have changed by less than $0.1 million.
Under current market conditions, we do not anticipate significant changes in prevailing interest rates for the next year, and we have not undertaken any activities to mitigate potential interest rate risk. There was no material change in interest rate
risk during the year ended December 31, 2016.
Counterparty Risk - As described in "-Commodity Price Risk," we enter into commodity derivative agreements to mitigate short-term price volatility. These derivative financial instruments present certain counterparty risks. We are exposed to potential loss if a counterparty fails to perform according to the terms of the agreement. The failure of any of the counterparties to fulfill their obligations to us could adversely affect our results of operations and cash flows. We do not require collateral or other security to be furnished by counterparties. We seek to manage the counterparty risk associated with these contracts by limiting transactions to well-capitalized, well-established, and well-known counterparties that have been approved by our senior officers. There can be no assurance, however, that our practice effectively mitigates counterparty risk.
Our exposure to counterparty risk has decreased during the last period as the amounts due to us from counterparties has decreased.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements and supplementary data are filed with this Annual Report in a separate section following Part IV, as shown in the index on page of this Annual Report.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report on Form 10-K (the “Evaluation Date”). Based on such evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the Evaluation Date, our disclosure controls and procedures were effective.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management's Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of our management, including Lynn A. Peterson, our Chief Executive Officer, and James P. Henderson, our Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016 based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2016.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Synergy Resources Corporation
Denver, Colorado
We have audited the internal control over financial reporting of Synergy Resources Corporation and subsidiaries (the "Company") as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2016 of the Company and our report dated February 23, 2017 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 23, 2017
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information responsive to Items 401, 405, 406, and 407 of Regulation S-K to be included in our definitive Proxy Statement for our Annual Meeting of Shareholders, to be filed within 120 days of December 31, 2016, pursuant to Regulation 14A under the Exchange Act (the “2017 Proxy Statement”), is incorporated herein by reference.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
The information responsive to Items 402 and 407 of Regulation S-K to be included in our 2017 Proxy Statement is incorporated herein by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information responsive to Items 201(d) and 403 of Regulation S-K to be included in our 2017 Proxy Statement is incorporated herein by reference.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE
The information responsive to Items 404 and 407 of Regulation S-K to be included in our 2017 Proxy Statement is incorporated herein by reference.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information responsive to Items 9(e) of Schedule 14A to be included in our 2017 Proxy Statement is incorporated herein by reference.
PART IV
ITEM 15
ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Financial Statements
See page for a description of the financial statements filed with this report.
Exhibits
* Filed herewith
** Furnished herewith
+ Management contract or compensatory plan or arrangement
SYNERGY RESOURCES CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Synergy Resources Corporation
Denver, Colorado
We have audited the accompanying consolidated balance sheet of Synergy Resources Corporation and subsidiaries (the "Company") as of December 31, 2016, and the related consolidated statements of operations, changes in shareholders' equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such 2016 consolidated financial statements present fairly, in all material respects, the financial position of Synergy Resources Corporation and subsidiaries as of December 31, 2016, and the results of their consolidated operations and their consolidated cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2017 expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
February 23, 2017
Denver, Colorado
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Synergy Resources Corporation
Denver, Colorado
We have audited the accompanying consolidated balance sheet of Synergy Resources Corporation (the “Company”) as of December 31, 2015, and the related statements of operations, changes in shareholders’ equity, and cash flows for the four months ended December 31, 2015 and for each of the years in the two-year period ended August 31, 2015. The Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Synergy Resources Corporation as of December 31, 2015, and the results of its operations and its cash flows for the four months ended December 31, 2015 and for each of the years in the two-year period ended August 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, in 2016 the Company changed its fiscal year from August 31 to December 31.
/s/ EKS&H LLLP
April 22, 2016
Denver, Colorado
SYNERGY RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements
SYNERGY RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)
The accompanying notes are an integral part of these consolidated financial statements
SYNERGY RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(in thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements
SYNERGY RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Supplemental Cash Flow Information (See Note 17)
The accompanying notes are an integral part of these consolidated financial statements
SYNERGY RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2016 and 2015 and August 31, 2015 and 2014
1.
Organization and Summary of Significant Accounting Policies
Organization: Synergy Resources Corporation is engaged in oil and gas acquisition, exploration, development, and production activities, primarily in the D-J Basin of Colorado. The Company’s common stock is listed and traded on the NYSE MKT under the symbol “SYRG.”
Basis of Presentation: The Company operates in one business segment, and all of its operations are located in the United States of America.
At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Synergy Resources Corporation. When such terms are used in this manner throughout this document, they are in reference only to the corporation, Synergy Resources Corporation, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.
The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiary. All significant intercompany balances and transactions have been eliminated in consolidation. The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).
Change of Year-End: On February 25, 2016, the Company's board of directors approved a change in fiscal year end from August 31 to December 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month fiscal year, which prior to September 1, 2015 ended on August 31, and beginning with December 31, 2015 ends on the December 31 of each year.
Use of Estimates: The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and natural gas reserves, goodwill, business combinations, derivatives, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically, and the effects of revisions are reflected in the consolidated financial statements in the period that it is determined to be necessary. Actual results could differ from these estimates.
Cash and Cash Equivalents: The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.
Cash Held in Escrow: Cash held in escrow includes deposits for purchases of certain oil and gas properties as required under the related purchase and sale agreements. As of December 31, 2016, the Company has placed $18.2 million in escrow to be released upon the second closing of the GC Acquisition. Please refer to Note 3, Acquisitions and Divestitures, for further information.
Oil and Gas Properties: The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves.
Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved oil and natural gas reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is the impairment test prescribed by SEC regulations. The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and natural gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties. The present value of estimated future net revenues is computed by applying current prices of oil and natural gas reserves to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion and prior impairments, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. During the year ended December 31, 2016, the Company recognized ceiling test impairments totaling $215.2 million.
The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period unless prices are defined by contractual arrangements. Prices are adjusted for basis or location differentials and are held constant for the productive life of each well.
Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and natural gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.
The determination of depletion expense, as well as the ceiling test calculation related to the recorded value of the Company’s oil and gas properties, is highly dependent on estimates of proved oil and natural gas reserves.
Capitalized Interest: The Company capitalizes interest on expenditures made in connection with acquisitions of mineral interests that are currently not subject to depletion and exploration and development projects that are in progress. Interest is capitalized during the period that activities are in progress to bring the projects to their intended use. See Note 10 for additional information.
Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenses are capitalized in the full cost pool. See Note 2 for additional information.
Other Property and Equipment: Support equipment (including such items as vehicles, computer equipment and software, office leasehold improvements, and office furniture and equipment) is stated at historical cost. Expenditures for support equipment relating to new assets or improvements are capitalized, provided the expenditure extends the useful life of an asset or extends the asset’s functionality. Support equipment is depreciated under the straight-line method using estimated useful lives ranging from three to five years. No depreciation is taken on assets classified as construction in progress until the asset is placed into service. Gains and losses are recorded upon retirement, sale, or disposal of assets. Maintenance and repair costs are recognized as period costs when incurred. The Company evaluates its support equipment for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable.
Accounts Payable and Accrued Expenses: Accounts payable and accrued expenses consist of the following (in thousands):
Revenue Payable: Revenue payable represents amounts collected from purchasers for oil and natural gas sales which are revenues due to other working or royalty interest owners. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received.
Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service. Calculation of an asset retirement obligation requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit adjusted risk-free rate. Estimates are periodically reviewed and adjusted to reflect changes.
The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made. When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the related asset. ARCs related to wells are capitalized to the full cost pool and subject to depletion. Over time, the liability increases for the change in its present value, while the net capitalized cost decreases over the useful life of the asset as depletion expense is recognized. In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment.
Business Combinations: The Company accounts for its acquisitions that qualify as businesses using the acquisition method under ASC 805, Business Combinations. Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain.
Goodwill: The Company’s goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination. Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. We have historically performed the annual impairment assessment as of August 31st. During 2016, we changed the date of our annual goodwill impairment assessment to October 1st. With respect to its annual goodwill testing date, management believes that this voluntary change in accounting method is preferable as it better aligns the annual impairment testing date with the Company’s new fiscal year end, which was also changed in 2016. This change in assessment date was applied prospectively and did not delay, accelerate, or avoid a potential impairment charge.
When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required two-step impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must perform the first step of the two-step impairment test and calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, there is an indication that impairment may exist, and the second step must be performed to measure the amount of impairment loss. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the goodwill exceeds the implied fair value of the goodwill. For purposes of assessing goodwill, the Company only has one reporting unit.
As a result of declining oil prices, the Company performed an interim goodwill test as of March 31, 2016. We also performed our annual goodwill impairment test as of October 1, 2016. Neither of these tests resulted in an impairment. For both tests, the Company utilized a market approach in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time. Changes in these assumptions or future economic conditions could impact the Company's conclusion regarding an impairment of goodwill and potentially result in a non-cash impairment loss in a future period.
Oil and Natural Gas Sales: The Company derives revenue primarily from the sale of oil and natural gas produced on its properties. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests. Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between thirty and ninety days after the date of production. Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.
Major Customers: The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of its oil and natural gas revenue (“major customers”) for each of the periods presented are shown in the following table:
* less than 10%
Based on the current demand for oil and natural gas, the availability of other buyers and the Company having the option to sell to other buyers if conditions warrant, the Company believes that its oil and natural gas production can be sold in the market in the event that it is not sold to the Company’s existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer.
Accounts receivable consist primarily of trade receivables from oil and natural gas sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.
Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table:
* less than 10%
The Company operates exclusively within the United States of America and, except for cash and cash equivalents, all of the Company’s assets are employed in, and all of its revenues are derived from, the oil and gas industry.
Lease Operating Expenses: Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, fuel consumed, supplies utilized in operating the wells and related equipment and facilities, property taxes, and insurance applicable to proved properties and wells and related equipment and facilities.
Stock-Based Compensation: The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model. For stock bonus awards and restricted stock units, fair value is the closing stock price for the Company's common stock on the grant date. For performance-vested stock units, fair value is calculated using a Monte Carlo simulation. The compensation is recognized over the vesting period of the grant. See Note 13 for additional information.
Income Tax: Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.
No significant uncertain tax positions were identified as of any date on or before December 31, 2016. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of December 31, 2016, the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 15 for further information.
Financial Instruments: Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or collars, to reduce the effect of price changes on a portion of its future oil and natural gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the consolidated statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 8.
Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of oil to a third party marketer and/or other counterparties that transport oil via pipelines. See Note 16 for additional information. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil that we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the expense as a transportation commitment charge in the consolidated statement of operations.
Recently Adopted Accounting Pronouncements:
On January 2017, the FASB issued Accounting Standards Update ("ASU") 2017-01, "Clarifying the Definition of a Business" ("ASU 2017-01"), which clarifies the definition of a business in ASC 805. The amendments narrow the definition of a business and provide a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. Specifically, ASU 2017-01: i) provides a “screen” for determining when a set is not a business. The screen requires a determination that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not a business; ii) specifies that if the screen’s threshold is not met, a set cannot be considered a business unless it includes an input and a substantive process that together significantly contribute to the ability to create outputs and provides a framework to help entities evaluate whether both an input and a substantive process are present; iii) it removes the evaluation of whether a market participant could replace the
missing elements; and iv) narrows the definition of the term “output.” ASU 2017-01 is effective in annual periods beginning after December 15, 2017, including interim periods therein. ASU 2017-01 must be applied prospectively on or after the effective date. Early adoption is permitted for transactions (i.e., acquisitions or dispositions) that occurred before the issuance date or effective date of the standard if the transactions were not reported in financial statements that have been issued or made available for issuance. We elected to early adopt this pronouncement effective October 1, 2016. As a result of adopting this pronouncement, we accounted for certain transactions as asset acquisitions which would have qualified as business combinations had we not adopted the standard.
Recent Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us.
In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" ("ASU 2016-18"), which amends ASC 230 to add or clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. Key requirements of ASU 2016-18 are as follows: 1) An entity should include in its cash and cash-equivalent balances in the statement of cash flows those amounts that are deemed to be restricted cash and restricted cash equivalents. ASU 2016-18 does not define the terms “restricted cash” and “restricted cash equivalents” but states that an entity should continue to provide appropriate disclosures about its accounting policies pertaining to restricted cash in accordance with other GAAP. ASU 2016-18 also states that any change in accounting policy will need to be assessed under ASC 250; 2) A reconciliation between the statement of financial position and the statement of cash flows must be disclosed when the statement of financial position includes more than one line item for cash, cash equivalents, restricted cash, and restricted cash equivalents; 3) Changes in restricted cash and restricted cash equivalents that result from transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows; and 4) An entity with a material balance of amounts generally described as restricted cash and restricted cash equivalents must disclose information about the nature of the restrictions. The guidance is effective for fiscal years beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, which must apply the guidance retrospectively to all periods presented. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements.
In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which intends to improve the accounting for share-based payment transactions. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions, including: (1) Accounting and Cash Flow Classification for Excess Tax Benefits and Deficiencies, (2) Forfeitures, and (3) Tax Withholding Requirements and Cash Flow Classification. ASU 2016-09 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We plan to adopt this pronouncement effective January 1, 2017. Upon adoption of this standard, we will no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we will account for forfeitures when they occur. We will apply this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.3 million to retained earnings as of the date of adoption. The adoption of the other provisions is not expected to materially impact the consolidated financial statements.
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)” (“ASU 2016-02”), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements.
In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period, with early adoption permitted for annual reporting periods beginning after December 15, 2016. Currently, we have not identified any contracts that would require a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales method of accounting. We are continuing to evaluate the provisions of these ASUs as pertinent to certain sales contracts and in particular as they relates to disclosure requirements.
There have been various updates issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations or cash flows.
2.
Property and Equipment
The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. As a result of these periodic reviews, the Company concluded that its net capitalized costs for oil and gas properties exceeded the ceiling amount, resulting in the recognition of ceiling test impairments totaling $215.2 million during the year ended December 31, 2016. During the four months ended December 31, 2015 and the year ended August 31, 2015, the Company's ceiling tests resulted in total impairments of $125.2 million and $16.0 million, respectively. No such ceiling test impairments were recognized during the year ended August 31, 2014.
The costs of unproved properties are withheld from the depletion base until such time as the properties are either developed or abandoned. Unproved properties are reviewed on a quarterly basis for impairment, and if impaired, are reclassified to proved properties and included in the depletion base. During the year ended December 31, 2016, these reviews indicated that the estimated carrying values of such assets exceeded fair values. Therefore, the Company recorded impairments of $18.9 million, and these costs were moved into the full cost pool and subject to the aforementioned ceiling test. No such impairments were recognized during the four months ended December 31, 2015 or the year ended August 31, 2014. However, during the year ended August 31, 2015, the Company recorded impairments of $15.4 million related to the fair value of its unproved properties.
Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenses in the amounts shown in the table below were capitalized in the full cost pool (in thousands):
Costs Incurred: Costs incurred in oil and gas property acquisition, exploration, and development activities for the periods presented were (in thousands):
Capitalized Costs Excluded from Depletion: The following table summarizes costs related to unproved properties that have been excluded from amounts subject to depletion at December 31, 2016 (in thousands):
There were no individually significant properties or significant development projects included in the Company’s unproved property balance. The Company regularly evaluates these costs to determine whether impairment has occurred or proved reserves have been established. The majority of these costs are expected to be evaluated and included in the depletion base within three years.
3.
Acquisitions and Divestitures
The Company seeks to acquire developed and undeveloped oil and gas properties, primarily in the core Wattenberg Field. The objective of these acquisitions is to provide additional mineral acres upon which the Company can drill wells and produce hydrocarbons. The Company acquired certain oil and natural gas and other assets that affect the comparability of its financial condition and results of operation between the year ended December 31, 2016 and 2015, as described below.
October 2016 Acquisition
During October 2016, the Company completed two acquisitions of certain assets for a total purchase price of $9.6 million composed of cash, forgiven receivables, and transferred liabilities. The acquired properties were comprised primarily of additional oil and gas leasehold interests in properties operated by the Company.
August 2016 Acquisition
During August 2016, the Company completed two acquisitions of certain assets for a total purchase price of $3.9 million composed of cash and assumed liabilities. The acquired properties were comprised primarily of undeveloped oil and gas leasehold interests.
June 2016 Acquisition
In May 2016, we entered into a purchase and sale agreement (the "GC Agreement") with a large publicly-traded company pursuant to which we agreed to acquire a total of approximately 72,000 gross (33,100 net) acres in an area referred to as the
Greeley-Crescent development area in the Wattenberg Field for $505 million (the "GC Acquisition"). Estimated net daily production from the acquired properties was approximately 2,400 BOE at the time of entering into the GC Agreement.
In June 2016, the Company closed on the portion of the assets comprised of the undeveloped oil and gas leasehold interests and non-operated production. The effective date of this part of the transaction was April 1, 2016. A second closing will cover the operated producing properties and is expected to be completed in 2017. The Company has placed $18.2 million in escrow to be released upon the second closing. For the second closing, the effective date will be April 1, 2016 for the horizontal wells to be acquired, and the first day of the calendar month in which the closing for such properties occurs for the vertical wells. The second closing is subject to certain closing conditions including the receipt of regulatory approval. Accordingly, the second closing of the transaction may not close in the expected time frame or at all.
The first closing on June 14, 2016 was for a total purchase price of $486.4 million, net of customary closing adjustments. The purchase price was composed of $485.1 million in cash plus the assumption of certain liabilities. The first closing encompassed approximately 33,100 net acres of oil and gas leasehold interests and related assets and net production of approximately 800 BOED at the time of entering into the GC Agreement.
The first closing was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 14, 2016. Transaction costs of $0.5 million related to the acquisition were expensed as incurred. The following table summarizes the purchase price and final fair values of assets acquired and liabilities assumed (in thousands):
(1) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 11.5%, and assumptions regarding the timing and amount of future development and operating costs.
For the year ended December 31, 2016, the results of operations of the acquired assets, representing approximately $5.3 million of revenue and $4.4 million of operating income, have been included in the Company's consolidated statements of operations.
The following table presents the unaudited pro forma combined results of operations for the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015 as if the first closing had occurred on September 1, 2014. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
February 2016 Acquisition
In February 2016, the Company completed the acquisition of undeveloped oil and gas leasehold interests for a total purchase price of $10.0 million. The purchase price has been allocated as $8.6 million to proved oil and gas properties and $1.4 million to unproved oil and gas properties. This allocation reflects significant use of estimates.
October 2015 Acquisition
In October 2015, the Company closed the acquisition of certain assets ("KPK Acquisition") from a private company for a total purchase price of $85.2 million, net of customary closing adjustments. The purchase price was composed of $35.0 million in cash and $49.8 million in restricted common stock of the Company plus the assumption of certain liabilities. The KPK Acquisition encompassed approximately 4,300 net acres of oil and gas leasehold interests and related assets and net production of approximately 1,200 BOED at the time of purchase.
The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of October 20, 2015. Transaction costs related to the acquisition were expensed as incurred. The following table summarizes the final purchase price and final fair values of assets acquired and liabilities assumed (in thousands):
(1) The fair value of the consideration attributed to the common stock under ASC 805 was based on the Company's closing stock price on the measurement date of October 20, 2015 (4,418,413 shares at $11.28 per share).
(2) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 12%, and assumptions regarding the timing and amount of future development and operating costs.
For the twelve months ended December 31, 2016 and the four months ended December 31, 2015, the results of operations of the acquired assets, representing approximately $5.1 million and $1.1 million of revenue and $4.5 million and $0.8 million of operating income, respectively, have been included in the Company's consolidated statements of operations.
The following table presents the unaudited pro forma combined results of operations for the four months ended December 31, 2015 and the year ended August 31, 2015 as if the transaction had occurred on September 1, 2014. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock and cash, additional depreciation expense, costs directly attributable to the acquisition, and operating costs incurred as a result of the assets acquired. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
Divestitures
In April 2016, the Company agreed to divest approximately 3,700 net undeveloped acres and 107 vertical wells primarily in Adams County, Colorado for total consideration of approximately $24.7 million in cash and the assumption by the buyer of $0.5 million in liabilities. The divested assets had associated production of approximately 200 BOED. The vertical well transaction closed in April 2016, and the undeveloped acreage transaction closed in June 2016. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.
4.
Depletion, depreciation, and accretion
Depletion, depreciation, and accretion consisted of the following (in thousands):
Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the year ended December 31, 2016, production of 4,271 MBOE represented 4.4% of estimated total proved reverses. For the four months ended December 31, 2015, production of 1,320 MBOE represented 2.0% of estimated total proved reserves. For the year ended August 31, 2015, production of 3,194 MBOE represented 5.3% of estimated total proved reserves. For the year ended August 31, 2014, production of 1,566 MBOE represented 4.6% of estimated total proved reserves. DD&A expense was $10.93 per BOE and $14.22 per BOE for the year ended December 31, 2016 and the four months ended December 31, 2015, respectively. DD&A expense was $20.62 per BOE and $21.05 per BOE for the years ended August 31, 2015 and 2014, respectively.
5.
Asset Retirement Obligations
Upon completion or acquisition of a well, the Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling site to its original use. The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations. Changes in estimates are reflected in the obligations as they occur. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost. The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands):
During the year ended December 31, 2016, the Company increased its asset retirement obligation by $3.7 million due to a revision to the expected timing of the future cash flows. During the year ended August 31, 2015, the Company increased its asset retirement obligation by $3.8 million due to a revision to its assumption of the average cost to plug and abandon each well.
6.
Revolving Credit Facility
The Company maintains a revolving credit facility with a bank syndicate with a maturity date of December 15, 2019. The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit. As of December 31, 2016, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation of $160 million. As of December 31, 2016, there was no outstanding principal balance as compared to a principal balance of $78 million as of December 31, 2015. The Company has an outstanding letter of credit of approximately $0.5 million. In October 2016, the Revolver was increased from $145 million to $160 million in connection with the semi-annual redetermination of the borrowing base. The next semi-annual redetermination is scheduled for May 2017.
Interest under the Revolver accrues monthly at a variable rate. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or LIBOR plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015 was 2.63%, 2.5%, and 2.5%, respectively.
Certain of the Company’s assets, including substantially all of the producing wells and developed oil and gas leases, have been designated as collateral under the Revolver. The borrowing commitment is subject to scheduled redeterminations on a semi-annual basis. If certain events occur or if the bank syndicate or the Company so elects, an unscheduled redetermination could be prepared.
The Revolver contains covenants that, among other things, restrict the payment of dividends and limit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of estimated proved developed producing or total proved reserves as projected in the semi-annual reserve report.
Furthermore, the Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. Under the requirements, the Company, on a quarterly basis, must not (a) at any time permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; or (b) as of the last day of any fiscal quarter permit its current ratio, as defined in the agreement, to be less than 1.0 to 1.0. As of December 31, 2016, the most recent compliance date, the Company was in compliance with these covenants and expects to remain in compliance throughout the next 12-month period.
7.
Notes Payable
In June 2016, the Company issued $80 million aggregate principal amount of 9% Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is June 13, 2021. Interest on the Senior Notes accrues at 9% and began accruing on June 14, 2016. Interest is payable on June 15 and December 15 of each year, beginning on December 15, 2016. The Senior Notes were issued pursuant to an indenture dated as of June 14, 2016 and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the Senior Notes were $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions. The associated expenses and underwriting discounts and commissions are amortized using the interest method at an effective interest rate of 10.5%. The net proceeds were used to fund the GC Acquisition as discussed further in Note 3.
At any time prior to December 14, 2018, the Company may redeem all or a part of the Senior Notes subject to the Make-Whole Price (as defined in the Indenture) and accrued and unpaid interest. On and after December 14, 2018, the Company may redeem all or a part of the Senior Notes at the redemption price at a specified percentage of the principal amount of the redeemed notes (104.50% for 2018, 102.25% for 2019, and 100% for 2020 and thereafter, during the twelve-month period beginning on December 14 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 14, 2018, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to 109% of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.
The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications.
As of December 31, 2016, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.
8.
Commodity Derivative Instruments
The Company has entered into commodity derivative instruments, as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the volumes and commodities covered and the relevant strike prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in the Revolver.
A "put" option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase. Conversely, a "call" option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period.
Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create "collars." We regularly utilize "no premium" (a.k.a. zero cost) collars where, at settlement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling price.
Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price over a specified term.
The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with four counterparties and an exchange. Two of the counterparties are lenders in the Revolver. The Company has netting arrangements with the counterparties that provide for the
offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.
The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.
The Company’s commodity derivative contracts as of December 31, 2016 are summarized below:
Offsetting of Derivative Assets and Liabilities
As of December 31, 2016 and 2015, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at election of both parties, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its accompanying consolidated balance sheets.
The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands):
The amount of gain (loss) recognized in the consolidated statements of operations related to derivative financial instruments was as follows (in thousands):
Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date, the proceeds from or cost of early liquidation of in-the-money derivative contracts, and the previously incurred premiums attributable to settled commodity contracts. During the year ended August 31, 2015, the Company liquidated oil derivatives with an average price of $82.79 and covering 372,500 barrels and received cash settlements of approximately $20.5 million. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):
Credit Related Contingent Features
As of December 31, 2016, two of the five counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the third and fourth counterparties, which are not lenders under the credit facility, are unsecured and do not require the posting of collateral. The
agreement with the fifth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility.
9.
Fair Value Measurements
ASC 820, Fair Value Measurements and Disclosure, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
•
Level 1: Quoted prices available in active markets for identical assets or liabilities;
•
Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and
•
Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The Company’s non-recurring fair value measurements include unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations. Please refer to Notes 2, 3, and 5 for further discussion of unproved properties, business combinations, and asset retirement obligations, respectively.
The Company determines the estimated fair value of its unproved properties using market comparables which are deemed to be a Level 3 input. See Note 2 for additional information.
The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed. The fair value of assets and liabilities acquired through business combinations is calculated using a net discounted cash flow approach for the proved properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and natural gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, the fair value is determined using the same inputs as described in the paragraph above. For the asset retirement obligation assumed, the fair value is determined using the same inputs as described in the paragraph below. See Note 3 for additional information.
The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation rate, and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Note 5 for additional information.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015 by level within the fair value hierarchy (in thousands):
Commodity Derivative Instruments
The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At December 31, 2016, derivative instruments utilized by the Company consist of puts and collars. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are primarily traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, cash held in escrow, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value.
The fair value of the notes payable is estimated to be $86.3 million at December 31, 2016. The Company determined the fair value of its notes payable at December 31, 2016 by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes as Level 2.
10.
Interest Expense
The components of interest expense are (in thousands):
11.
Shareholders’ Equity
The Company's classes of stock are summarized as follows:
Preferred Stock may be issued in series with such rights and preferences as may be determined by the Board of Directors. Since inception, the Company has not issued any preferred shares. As of December 31, 2016, the shareholders had approved the number of common shares authorized for issuance of 300,000,000.
Shares of the Company’s common stock were issued during the year ended December 31, 2016, the four months ended December 31, 2015 and each of the years ended August 31, 2015, and 2014, as described further below.
Sales of common stock
During the year ended December 31, 2016, the four months ended December 31, 2015, and the years ended August 31, 2015 and 2014, the Company sold shares of its common stock in public offerings as follows:
•
In May and June 2016, the Company completed the sale of common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC.
•
In April 2016, the Company completed the sale of common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC.
•
In January 2016, the Company completed the sale of common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC.
•
In February 2015, the Company completed the sale of common stock in an underwritten public offering led by Seaport Global Securities LLC.
A summary of the transactions is shown in the following table. Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions and expenses of the offering.
In January 2016, the Company completed a public offering of its common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC. The Company agreed to sell 14,000,000 shares of its common stock to the Underwriters at a price of $5.545 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 2,100,000 shares of common stock on the same terms and conditions. The option was exercised on January 26, 2016, bringing the total number of shares issued to 16,100,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $89.2 million. Proceeds from the offering were used for general corporate purposes, including the continued development of our acreage position in the Wattenberg Field and repayment of amounts borrowed under the Revolver.
In April 2016, the Company completed a public offering of its common stock in an underwritten public offering led by Credit Suisse Securities (USA) LLC. The Company agreed to sell 19,500,000 shares of its common stock to the Underwriters at a price of $7.3535 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 2,925,000 shares of common stock on the same terms and conditions. The option was exercised on April 12, 2016, bringing the total number of shares issued to 22,425,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $164.8 million. Proceeds from the offering were used for general corporate purposes, including the continued development of our acreage position in the Wattenberg Field and funding a portion of the purchase price of the GC Acquisition described in Note 3.
In May 2016, the Company completed a public offering of its common stock in an underwritten public offering. The Company agreed to sell 45,000,000 shares of its common stock to the Underwriters at a price of $5.597 per share. In addition, pursuant to the Underwriting Agreement, the Underwriters were granted an option, exercisable within 30 days, to purchase up to an additional 6,750,000 shares of common stock on the same terms and conditions. The option was exercised on June 6, 2016, bringing the total number of shares issued to 51,750,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $289.4 million. The Company used the proceeds of the offering to pay a portion of the purchase price of the GC Acquisition described in Note 3.
Common stock issued for acquisition of mineral property interests
During the periods presented, the Company issued shares of common stock in exchange for mineral property interests. The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction.
Common stock warrants
The Company previously issued warrants to purchase common stock. There were no warrants outstanding as of August 31, 2015, December 31, 2015 and December 31, 2016. The following reflects the activity since September 1, 2013:
Series C - During the year ended August 31, 2010, the Company issued 9,000,000 Series C warrants in connection with a unit offering. Each unit included one convertible promissory note with a face value of $100,000 and 50,000 Series C warrants. Each Series C warrant entitled the holder to purchase one share of common stock for $6.00 and expired on December 31, 2014, if not previously exercised. During the years ended August 31, 2015, 2014, and 2013, the following Series C warrants were exercised: 2,561,415, 5,938,585, and 500,000, respectively.
Series D - During the year ended August 31, 2010, the Company issued 1,125,000 Series D warrants to the placement agent for the Series C unit offering. Each Series D warrant entitled the holder to purchase one share of common stock for $1.60, and contained a net settlement provision that provided for exercise of the warrants on a cashless basis. The Series D warrants expired, if not previously exercised, on December 31, 2014. During the years ended August 31, 2015, 2014, and 2013, the following warrants were exercised: 1,058, 140,744, and 627,799, respectively.
Investor Relations Warrants - During the year ended August 31, 2012, the Company issued 100,000 warrants to a firm providing investor relations services (the "Investor Relations Warrants"). Each Investor Relations Warrant entitled the holder to purchase one share of common stock for $2.69, and contained a net settlement provision that provided for exercise of the warrants on a cashless basis. The warrants became exercisable in equal quarterly installments over a one-year period. During the year ended August 31, 2013, warrants to purchase 50,000 shares became exercisable and warrants to purchase 50,000 shares were forfeited due to early termination of the agreement with the firm. During the years ended August 31, 2015, 2014, and 2013, the following Investor Relations Warrants were exercised: nil, 25,000, and 25,000, respectively.
The following table summarizes activity for common stock warrants for the periods presented:
12. Earnings Per Share
Basic earnings per share includes no dilution and is computed by dividing net income (loss) by the weighted-average number of shares outstanding during the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company. The number of potential shares outstanding relating to stock options, non-vested performance-vested stock units, non-vested restricted stock units, stock bonus shares, and warrants is computed using the treasury stock method. Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share.
The following table sets forth the share calculation of diluted earnings per share:
The following potentially dilutive securities outstanding for the periods presented were not included in the respective earnings per share calculation above as such securities had an anti-dilutive effect on earnings per share:
1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.
13.
Stock-Based Compensation
In addition to cash compensation, the Company may compensate employees and directors with equity based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, warrants, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the “vesting phase”). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo Model. For the periods presented, all stock-based compensation was either classified as a component within general and administrative expense in the Company's consolidated statements of operations or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool.
The amount of stock-based compensation was as follows (in thousands):
General Description of Stock Award Plans
In December 2015, the Company's shareholders approved the 2015 Equity Incentive Plan (the "2015 Plan"). The 2015 Plan replaced three equity compensation plans: (i) a 2011 non-qualified stock option plan, (ii) a 2011 incentive stock option plan, and (iii) a 2011 stock bonus plan (the "2011 Plans"). No additional options or stock bonus shares will be issued under the 2011 Plans.
The 2015 Plan authorizes stock options, stock appreciation rights, restricted stock, restricted stock units, stock bonuses and other forms of awards that may be granted or denominated in the Company’s common stock or units of the Company’s common stock as well as cash bonus awards. Employees, directors, officers, consultants, and advisors are eligible to receive such awards, provided that bona fide services are rendered by such consultants or advisors (other than services in connection with the offering or sale of securities or as a market maker or promoter of securities of the Company).
As of December 31, 2016, there were 4,500,000 common shares authorized for grant under the 2015 Plan, of which 2,149,238 shares were remaining for future issuance.
Stock options
During the respective periods, the Company granted the following stock options:
The assumptions used in valuing stock options granted during each of the periods presented were as follows:
The following table summarizes activity for stock options for the periods presented:
The following table summarizes information about issued and outstanding stock options as of December 31, 2016:
The estimated unrecognized compensation cost from stock options not vested as of December 31, 2016, which will be recognized ratably over the remaining vesting phase, is as follows:
Restricted stock units and stock bonus awards
The Company grants shares of restricted stock units and stock bonus awards to directors, eligible employees, and officers as a part of its equity incentive plan. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each restricted stock unit or stock bonus award represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in equal increments over three to five years. Restricted stock units and stock bonus awards are valued at the closing price of the Company’s common stock on the grant date and are recognized over the vesting period of the award.
The following table summarizes activity for restricted stock units and stock bonus awards for the periods presented:
The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of December 31, 2016, which will be recognized ratably over the remaining vesting phase, is as follows:
Performance-vested stock units
In March 2016, the Company granted performance-vested stock units ("PSUs") to certain executives under its long term incentive plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. The shares issued for PSUs are determined based on the Company’s performance over a three-year measurement period and vest in their entirety at the end of the measurement period. The PSUs will be settled in shares of the Company’s common stock following the end of the three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion for the PSUs is based on a comparison of the Company’s total shareholder return ("TSR") for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the vesting criterion is linked to the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards.
The fair value of the PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well as the volatilities for each of the Company’s peers.
The assumptions used in valuing the PSUs granted were as follows:
During the year ended December 31, 2016, the Company granted 490,713 PSUs to certain executives. The fair value of the PSUs granted during the year ended December 31, 2016 was $4.0 million. As of December 31, 2016, unrecognized compensation expense for PSUs was $2.8 million and will be amortized through 2018. A summary of the status and activity of PSUs is presented in the following table:
1 The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.
14.
Defined Contribution Plan
The Company sponsors a 401(k) defined contribution plan for eligible employees. Company contributions to the 401(k) plan consist of a discretionary matching contribution equal to 100% of compensation deferrals not to exceed 3% of eligible compensation plus 50% of compensation deferrals in excess of 3% of eligible compensation not to exceed more than 5% of eligible compensation. The Company contributed approximately $0.4 million for year ended December 31, 2016, $0.1 million for the four months ended December 31, 2015, and $0.1 million during the years ended August 31, 2015 and 2014 to the plan. Effective January 1, 2017, the Company modified its 401(k) plan to include a discretionary matching contribution equal to 100% of compensation deferrals not to exceed 6% of eligible compensation.
15.
Income Taxes
The income tax provision is comprised of the following (in thousands):
A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands):
In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making this assessment. Judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits, and other
deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.
The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands):
At December 31, 2016, the Company has a net operating loss carryforward for federal and state tax purposes of approximately $140.3 million that could be utilized to offset taxable income of future years. For financial reporting purposes, the Company has net operating losses of approximately $128.1 million for federal and state. The difference of $12.2 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated. Substantially all of the carryforward will commence expiring in 2031, 2032, and 2033.
At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making an assessment as to the future utilization of deferred tax assets. During the year ended December 31, 2016, the Company recognized a full valuation allowance on its net deferred tax assets. This decision was based on the fact that for the preceding three-year period, the Company has reported cumulative net losses.
The ability of the Company to utilize its NOL carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company’s taxable income that can be offset by these carryforwards.
As of December 31, 2016, the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards and would not result in significant interest expense or penalties. Most of the Company's tax returns filed since August 31, 2012 are still subject to examination by tax authorities.
16.
Other Commitments and Contingencies
Volume Commitments
During 2014, the Company entered into oil transportation agreements with three counterparties. Deliveries under two of the transportation agreements commenced during the four months ended December 31, 2015. Deliveries under the third transportation agreement commenced during the year ended December 31, 2016.
In collaboration with several other producers and DCP Midstream, we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin. The plan includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system, both currently expected to be completed by late 2018, although the start-up date is undetermined at this time. Our share of the commitment will require 46.4 MMcf per day to be delivered after the plant in-service date for a period of 7 years. This contractual obligation can be reduced by our proportionate share of the collective volumes delivered to the plant by other producers in the D-J Basin that are in excess of the total commitment.
Pursuant to these agreements, we must deliver specific amounts of oil and natural gas either from our own production or from oil and natural gas that we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. Our commitments over the next five years, excluding the contingent commitment described in the preceding paragraph, are as follows:
During the year ended December 31, 2016 and four months ended December 31, 2015, the Company incurred transportation deficiency charges of $0.6 million and $2.8 million, respectively, as we were unable to meet all of the obligations during the period. No such charges were incurred during the years ended August 31, 2015 and 2014.
Office leases
In September 2016, the Company entered into a new sixty-five-month lease for the Company’s principal office space located in Denver, which is expected to commence in the first quarter of 2017. At the Company's current location, lease expense is approximately $50,000 per month which will continue until the new space is ready to be occupied. Rent under the new lease is approximately $62,000 per month. In July 2016, the Company entered into a field office lease in Greeley which requires monthly payments of $7,500 through October 2021. A schedule of the minimum lease payments under non-cancelable operating leases as of December 31, 2016 follows (in thousands):
Rent expense for offices leases was $1.0 million for year ended December 31, 2016, $0.3 million for the four months ended December 31, 2015, and $0.3 million and $0.2 million for the years ended August 31, 2015 and 2014, respectively.
Litigation
From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current proceedings are reasonably likely to have a material adverse impact on its business, financial position, results of operations, or cash flows.
On June 1, 2015, the Company filed a complaint in the District Court of Weld County, Colorado, against Briller, Inc., R.W.L. Enterprises and Robert W. Loveless (together, the "Defendants") arising from a dispute concerning the validity of certain
leases covering oil and gas properties in Weld County, Colorado. In June 2015, the Defendants removed the case to the Federal District Court of Colorado and filed an answer and counterclaims including claims for trespass. The Company and Defendants entered into a settlement agreement on December 6, 2016, resolving all claims and counterclaims related to the litigation. The terms of the settlement agreement did not have a material effect on the Company.
In July 2016, the Company was informed by the CDPHE that it expects to expand its inspection of the Company's facilities in connection with a Compliance Advisory previously issued by the CDPHE and subsequent inspections conducted by the CDPHE. The Compliance Advisory alleged issues at five Company facilities regarding leakages of volatile organic compounds from storage tanks, all of which were promptly addressed. A subsequent February 2017 tolling agreement between the Company and CDPHE addressed alleged similar storage tank leakage issues at other Company facilities in Colorado. We are working with the CDPHE to respond to any continuing concerns. We cannot predict the outcome of this matter, but we expect that any potential resolution of these claims would be on a field-wide basis.
17.
Supplemental Schedule of Information to the Consolidated Statements of Cash Flows
The following table supplements the cash flow information presented in the consolidated financial statements for the periods presented (in thousands):
18.
Unaudited Oil and Natural Gas Reserves Information
Oil and Natural Gas Reserve Information: Proved reserves are the estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made). Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Proved oil and natural gas reserve information as of the period ends presented and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott. Reserve information for the properties was prepared in accordance with guidelines established by the SEC.
The reserve estimates prepared as of each of the period ends presented were prepared in accordance with “Modernization of Oil and Gas Reporting” published by the SEC. The guidance included updated definitions of proved developed and proved undeveloped oil and natural gas reserves, oil and natural gas producing activities, and other terms. Proved oil and natural gas reserves were calculated based on the prices for oil and natural gas during the twelve-month period before the respective determination date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period, rather than the year-end spot prices. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking. The guidance broadened the types of technologies that may be used to establish reserve estimates.
The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and natural gas reserve quantities and changes therein for each of the periods presented:
Notable changes in proved reserves for the year ended December 31, 2016 included:
•
Purchases of reserves in place. For the year ended December 31, 2016, purchases of reserves in place of 55,991 MBOE were primarily attributable to the acquisition of proved reserves in the GC Acquisition. Please see Note 3 for further information.
•
Revision of previous estimates. For the year ended December 31, 2016, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 21,213 MBOE primarily as a result of the removal of certain legacy PUD locations as they are now expected to be developed beyond the three-year drilling plan.
•
Extensions and discoveries. For the year ended December 31, 2016, total extensions and discoveries of 3,627 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 6 successful exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.
Notable changes in proved reserves for the four months ended December 31, 2015 included:
•
Purchases of reserves in place. For the four months ended December 31, 2015, purchases of reserves in place of 14,207 MBOE were attributable to the acquisition of proved reserves. Please see Note 3 for further information.
•
Revision of previous estimates. For the four months ended December 31, 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 17,407 MBOE. As the Company continued to revise its drilling plans, the development plan removed undeveloped reserves that are not projected to be drilled in the next three years and reflected the lower development costs anticipated from transitioning to a monobore wellbore design and longer horizontal wells; in addition, we high-graded our inventory of wells to be drilled.
•
Extensions and discoveries. For the four months ended December 31, 2015, total extensions and discoveries of 18,647 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 9 successful exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.
Notable changes in proved reserves for the year ended August 31, 2015 included:
•
Purchases of reserves in place. For the year ended August 31, 2015, purchases of reserves in place of 7,860 MBOE were attributable to the acquisition of proved reserves.
•
Revision of previous estimates. For the year ended August 31, 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 2,513 MBOE. As the Company continued to revise its drilling plans toward horizontal drilling, the vertical proved undeveloped and vertical developed non-producing locations were removed from its development plan.
•
Extensions and discoveries. For the year ended August 31, 2015, total extensions and discoveries of 23,696 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 67 successful exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.
Notable changes in proved reserves for the year ended August 31, 2014 included:
•
Purchases of reserves in place. For the year ended August 31, 2014, purchases of reserves in place of 2,021 MBOE were attributable to the acquisition of producing oil and natural gas wells and undeveloped acreage.
•
Revision of previous estimates. For the year ended August 31, 2014, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 591 MBOE.
•
Extensions and discoveries. For the year ended August 31, 2014, total extensions and discoveries of 17,357 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company’s proved reserves.
Standardized Measure of Discounted Future Net Cash Flows: The following discussion relates to the standardized measure of future net cash flows from our proved reserves and changes therein related to estimated proved reserves. Future oil and natural gas sales have been computed by applying average prices of oil and natural gas as discussed below. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the period based on period-end costs. The calculation assumes the continuation of existing economic conditions, including the use of constant prices and costs. Future income tax expenses were calculated by applying period-end statutory tax rates, with consideration of future tax rates already legislated, to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and natural gas producing activities. All cash flow amounts are discounted at 10% annually to derive the standardized measure of
discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and natural gas reserves. Actual future net cash flows from oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and natural gas, the amount and timing of actual production, supply of and demand for oil and natural gas, and changes in governmental regulations or taxation.
The following table sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by the SEC (in thousands):
There have been significant fluctuations in the posted prices of oil and natural gas during the last three years. Prices actually received from purchasers of the Company’s oil and natural gas are adjusted from posted prices for location differentials, quality differentials, and Btu content. Estimates of the Company’s reserves are based on realized prices.
The following table presents the prices used to prepare the reserve estimates based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials:
The prices for the December 31, 2016 oil and natural gas reserves are based on the twelve-month arithmetic average for the first of month prices as adjusted for our differentials from January 1, 2016 through December 31, 2016. The December 31, 2016 oil price of $36.07 per barrel (West Texas Intermediate Cushing) was $5.26 lower than the December 31, 2015 oil price of $41.33 per barrel. The December 31, 2016 natural gas price of $2.44 per Mcf (Henry Hub) was $0.16 lower than the December 31, 2015 price of $2.60 per Mcf.
Changes in the Standardized Measure of Discounted Future Net Cash Flows: The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands):
19.
Unaudited Financial Data
The Company’s unaudited quarterly financial information is as follows (in thousands, except share data):
The Company’s unaudited financial information for the four months ended December 31, 2014 is as follows (in thousands, except share data):
The sum of net income (loss) per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year.
Common share equivalents were excluded from the calculation of net income (loss) per share as the inclusion of the common share equivalents was anti-dilutive.
The Company has recast this quarterly financial information for the year ended December 31, 2015 to reflect the change in the Company's fiscal year.
20.
Subsequent Events
In January 2017, we executed a purchase and sale agreement with a private party resulting in the divestiture of acreage outside of the Company's core development area. The transaction resulted in the Company divesting approximately 10,000 net undeveloped acres and approximately 700 BOED of associated production for $71 million. The transaction is expected to close in the first quarter of 2017.
In January 2017, we executed a purchase and sale agreement with a private party for the acquisition of undeveloped oil and gas leasehold interests for a total purchase price of $25 million. The transaction is expected to close in the first quarter of 2017.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(a) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized on the 23rd day of February, 2017.
SYNERGY RESOURCES CORPORATION
/s/ Lynn A. Peterson
Lynn A. Peterson, Principal Executive Officer
/s/ James P. Henderson
James P. Henderson, Principal Financial Officer
/s/ Jared C. Grenzenbach
Jared C. Grenzenbach, Principal Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of l934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS
Units of Measurement
The following presents a list of units of measurement used throughout the document:
Bbl - One stock tank barrel of oil, or 42 U.S. gallons liquid volume of NGLs.
Bcf - One billion cubic feet of natural gas volume.
BOE - One barrel of oil equivalent, which combines Bbls of oil and Mcf of natural gas by converting each six Mcf of natural gas to one Bbl of oil.
BOED - BOE per day.
Btu - British thermal unit.
MBOE - One thousand BOE.
MMBbls - One million barrels of oil.
Mcf - One thousand cubic feet of natural gas volume.
MMBtu - One million British thermal units.
MMcf - One million cubic feet of natural gas volume.
MMcf/d - MMcf per day.
Glossary of Industry Terms
The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report:
Completion - Refers to the work performed and the installation of permanent equipment for the production of oil and natural gas from a recently drilled well.
Developed acreage - Acreage assignable to productive wells.
Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differentials - The difference between the oil and natural gas index spot price and the corresponding cash spot price in a specified location.
Dry gas - Natural gas is considered dry when its composition is over 90% pure methane.
Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or natural gas well.
EURs - Estimated ultimate recovery.
Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.
Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest.
Gross acres or wells - Refers to the total acres or wells in which we have a working interest.
Henry Hub - Henry Hub index. Natural gas distribution point where prices are set for natural gas futures contracts traded on the NYMEX.
Horizontal drilling - A drilling technique that permits the operator to drill a horizontal wellbore from the bottom of a vertical section of a well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling
techniques allow and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.
Horizontal well - A well that has been drilled using the horizontal drilling technique. The term "horizontal wells" include wells where the productive length of the wellbore is drilled more or less horizontal to the earth's surface, to intersect the target formation on a parallel basis.
Hydraulically fracture or Hydraulic fracturing - a procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability, thereby allowing the release of trapped hydrocarbons.
Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners.
Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from "wet" natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other condensates.
Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest.
Net revenue interest - Refers to all working interests less all royalties.
Net production - oil and natural gas production that we own, less royalties and production due to others.
Non-operated - A project in which another entity has responsibility over the daily operation of the project.
NYMEX - New York Mercantile Exchange.
OPEC - the Organization of Petroleum Exporting Countries.
Operator - The individual or company responsible for the exploration, development and/or production of an oil or natural gas well or lease.
Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest.
Possible reserves - This term is defined in SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates.
Present value of future net revenues or (PV-10) - PV-10 is a Non-GAAP financial measure calculated before the imposition of corporate income taxes. It is derived from the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves prepared in accordance with the provisions of Accounting Standards Codification Topic 932, Extractive Activities - Oil and Gas. The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and the periods in which they are expected to be developed and produced based on specified economic conditions. The estimated future production is based upon benchmark prices that reflect the unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas during the relevant period. The resulting estimated future cash inflows are then reduced by estimated future costs to develop and produce reserves based on current cost levels. No deduction is made for the depletion of historical costs or for indirect costs, such as general corporate overhead. Present values are computed by discounting future net revenues by 10% per year.
Probable reserves - This term is defined in SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
Productive well - A well that is not a dry well or dry hole, as defined above, and includes wells that are mechanically capable of production.
Proved developed non-producing reserves or PDNPs - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.
Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.
Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves.
Proved reserves - This term means "proved oil and natural gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Recomplete or Recompletion - The modification of an existing well for the purpose of producing oil and natural gas from a different producing formation.
Reserves - Estimated remaining quantities of oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil, natural gas and NGLs or related substances to market, and all permits and financing required to implement the project.
Royalty - An interest in an oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Section - A square tract of land one mile by one mile, containing 640 acres.
Spud - To begin drilling; the act of beginning a hole.
Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10%. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense.
Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves.
Vertical well - Directional wells that are drilled at an angle toward a target area where the productive length of the wellbore intersects the target formation on a perpendicular basis.
Wet gas or wet natural gas - Natural gas that contains a larger quantity of hydrocarbon liquids than dry natural gas, such as NGLs, condensate and oil.
Working interest - An interest in an oil and gas lease that gives the owner of the interest the right to drill and produce oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations.
Workover - Major remedial operations on a producing well to restore, maintain or improve the well's production.
WTI - West Texas Intermediate. A specific grade of oil used as a benchmark in oil pricing. It is the underlying commodity of NYMEX's oil futures contracts.