ITEM 1.
BUSINESS
Overview
SRC Energy Inc. ("we," "us," "our," "SRC," or the "Company") is an independent oil and gas company engaged in the acquisition, development, and production of oil, natural gas, and NGLs 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. 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 formation as well as the three benches of the Niobrara formation, all of 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 78% of our proved producing reserves and anticipate operating substantially all of our future net drilling locations.
During the year ended December 31, 2017, 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. Most notably, in December 2017, we closed on the acquisition of certain undeveloped land and non-operated production in the Greeley-Crescent development area in Weld County for $569.5 million, comprised of $568.1 million in cash and the assumption of certain liabilities. The transaction included approximately 30,200 net acres and approximately 2,500 BOE net daily production from the acquired non-operated properties. The acquired acreage represents a significant increase in the Company’s leasehold and drillable locations in the Greeley-Crescent area. Combined with SRC’s existing acreage, this results in a consolidated core position of approximately 88,300 net acres. This contiguous footprint creates further opportunities to drive operational efficiencies with over 1,700 identified gross well locations with predominantly mid- and long-lateral design.
As of December 31, 2017, we are the operator of 572 gross (551 net) producing wells, of which 227 gross (218 net) are Codell or Niobrara horizontal wells. The Company has also participated as a non-operator in 442 gross (99 net) producing wells. In addition, there were 51 gross (47 net) operated wells in various stages of drilling or completion as of December 31, 2017, which excludes 19 gross (16 net) wells for which we have only set surface casings.
For the year ended December 31, 2017, 2016 and 2015, our average net daily production was 34,194 BOED, 11,670 BOED, and 9,548 BOED, respectively. As of December 31, 2017, over 98% 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 are located either in or adjacent to the Wattenberg Field, and we seek to acquire developed and undeveloped oil and gas properties in the same area. 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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Use the latest technology to maximize returns and improve hydrocarbon recovery. Our development objective for individual well optimization is to drill and complete wells with lateral lengths of 7,000' to 10,000'. 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 implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development program.
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Operate in a safe manner and seek to minimize our impact on surrounding stakeholders. While our scale of operations has increased significantly, we continue to focus on maintaining a safe workplace for our employees and contractors. Further, as technology for resource development has advanced, we seek to utilize best industry practices to meet or exceed regulatory requirements while reducing our impacts on neighboring communities.
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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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Acquire and develop assets near established infrastructure. We have made acquisitions of contiguous acreage and aligned our development plans where technically-capable, financially-stable midstream companies have existing assets and plans for additional investment. We work collaboratively with these companies to proactively identify expansion opportunities that complement our development plans while reducing truck traffic.
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 lead to a high success rate and 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. Our core position is situated in an area where there is extensive infrastructure that continues to be expanded.
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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. Our modest 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, 2017 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, 2017, approximately 72% of total gross revenues were oil and condensate, 16% were natural gas, and 12% were natural gas liquids. We believe that this balanced commodity mix will provide diversification of sources of cash flow.
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Focus on efficiency and cost control. 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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Safe workplace and reduced impact on surrounding areas. Our employees and contractors are important to us, so we strive to maintain a safety-first approach in our operations. Likewise, we seek to incorporate current technologies to meet regulatory requirements while reducing our impact on the environment and neighboring communities. Toward this effort, modern drilling and completion techniques allow us to concentrate our operations on a reduced number of surface
locations. As the new locations are developed, we have decreased the overall number of wells by plugging and abandoning vertical wells, allowing us to return those sites to surface owners.
Properties
As of December 31, 2017, our estimated net proved oil and natural gas reserves, as prepared by Ryder Scott Company, L.P. ("Ryder Scott"), an independent reserve engineering firm, were 69.4 MMBbls of oil and condensate, 559.9 Bcf of natural gas, and 64.0 MMBbls of natural gas liquids. As of December 31, 2017, we had approximately 98,600 gross and 88,300 net acres under lease in the Wattenberg Field. We also have non-core leasehold in other areas of Colorado and southwest Nebraska approximating 238,500 gross and 200,500 net acres.
We currently operate over 78% of our proved producing reserves, and substantially all of our drilling and completion expenditures during the year ended December 31, 2017 were focused on the Wattenberg Field. Substantially all of our drilling and completion expenditures for the 2018 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 Developments
Acquisitions
In December 2017, the Company completed the purchase of a total of approximately 30,200 net acres in the Greeley-Crescent development area in Weld County Colorado, primarily south of the city of Greeley, for $569.5 million, comprised of $568.1 million in cash and the assumption of certain liabilities ("GCII Acquisition"). Estimated net daily production from the acquired non-operated properties was approximately 2,500 BOE at the time we entered into the agreement governing the transaction (the "GCII Agreement"). The effective date of this part of the transaction was November 1, 2017. The GCII Agreement also contemplates a second closing at which we will acquire operated producing properties subject to certain regulatory restrictions. The purchase price payable at the second closing will be determined based on the amount of then-current production from the properties conveyed and is expected to be completed in 2018. For the second closing, the effective date will be the first day of the calendar month in which the closing for such properties occurs. 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.
In September 2017, we completed the second closing contemplated by the May 2016 purchase and sale agreement (the "GC Agreement") pursuant to which we agreed to acquire a total of approximately 33,100 net acres in the Greeley-Crescent area for $505 million (the "GC Acquisition"). At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company. The total purchase price for the second closing was $30.3 million, composed of cash of $6.3 million and assumed liabilities of $24.0 million. The assumed liabilities included $20.9 million for asset retirement obligations.
In August 2017, we entered into an agreement with a third party to trade approximately 3,200 net acres of the Company's non-contiguous acreage for approximately 3,200 net acres within the Company's core operating area. This transaction closed in the fourth quarter of 2017. We also executed a purchase and sale agreement with a private party for the acquisition of approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million, composed of cash and assumed liabilities.
In March 2017, we acquired developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.1 million, composed of cash and assumed liabilities.
Divestitures
During the year ended December 31, 2017, we completed divestitures of approximately 16,000 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $91.6 million in cash and the assumption by the buyers of $5.2 million in asset retirement obligations and $22.2 million in other liabilities. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.
Equity Offering
In November 2017, the Company, in connection with a registered underwritten public offering of its common stock (the “Offering”), entered into an underwriting agreement (the “Underwriting Agreement”) with the several underwriters named therein (the “Underwriters”) and pursuant to which the Company agreed to sell 35,000,000 shares of its common stock to the Underwriters at a price of $7.76 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 5,250,000 shares of common stock on the same terms and conditions. The option was exercised in full on November 10, 2017, bringing the total number of shares issued in the Offering to 40,250,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $312.2 million. The Company used the proceeds of the offering to pay a portion of the purchase price of the GCII Acquisition and to repay amounts borrowed under the Revolver.
Revolving Credit Facility
We continue to maintain a borrowing arrangement with our bank syndicate (sometimes referred to as the “Revolver”) to provide us with liquidity that can 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, 2017, the Revolver 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.
In September 2017, the lenders under the Revolver completed their regular semi-annual redetermination of our borrowing base. The borrowing base was increased from $225 million to $400 million. The next semi-annual redetermination is scheduled for April 2018. Due to outstanding letters of credit, approximately $399.5 million of the borrowing base was available to use for future borrowings as of December 31, 2017, subject to our covenant requirements.
2025 Senior Notes
In November 2017, the Company issued $550 million aggregate principal amount of its 6.25% Senior Notes (the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 (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 2025 Senior Notes were $538.1 million after deductions of $11.9 million for expenses and underwriting discounts and commissions. The net proceeds were used to fund the GCII Acquisition, repay the 2021 Senior Notes, and pay off the outstanding Revolver balance. 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.
2021 Senior Notes
In December 2017, the Company repurchased all $80 million aggregate principal amount of its 9% Senior Notes (the "2021 Senior Notes"). At the time of repurchase, the Company made a required make whole payment of $8.2 million and wrote-off deferred issuance costs of $3.6 million.
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 year ended December 31, 2017, we turned 109 gross operated wells to sales in ten separate spacing units. None of the wells are classified as exploratory and 109 of the gross operated wells are classified as development.
* Includes 63 gross (11 net) productive wells which we participated in on a non-operated basis.
** Includes 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. As of December 31, 2017, we were the operator of 51 gross (47 net) wells in progress, which excludes 19 gross (16 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:
* Adjusted to include the effect of transportation and gathering expenses.
Major Customers
We sell our crude oil, natural gas, and NGLs to various purchasers under multiple contractual arrangements. For crude oil, we have several arrangements, ranging from month-to-month to long-term commitments. Notably, in 2014, we secured contracts with oil purchasers who transport oil via pipelines. Under these contracts, we entered into 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. With current infrastructure and expansion plans, we believe that gas gathering and processing and oil takeaway capacity will be sufficient to meet our anticipated production growth. See further discussion in Note 16 to our consolidated financial statements. For the year ended December 31, 2017, three of our customers account for more than 10% of our revenues.
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, 2017, 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, 2017, 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 143% from December 31, 2016 to December 31, 2017. At December 31, 2017, we had estimated proved reserves of 69.4 MMBbls of oil and condensate, 559.9 Bcf of natural gas, and 64.0 MMBbls of natural gas liquids. The estimated standardized measure of future net cash flow from our reserves at December 31, 2017 was $1.6 billion and the estimated PV-10 value of our reserves at that date was $1.8 billion. 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, 2017 increased compared to December 31, 2016 by $1.3 billion. The increase in estimated proved reserve quantities and PV-10 value is primarily due to acquisitions completed during 2017, extensions resulting in new proved undeveloped reserve increases, increased pricing during 2017, and revisions resulting in probable reserves being recognized as proved producing reserves.
Ryder Scott prepared the estimates of our proved reserves, future production, and income attributable to our leasehold interests as of December 31, 2017. 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 26, 2018, 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, Chief Operations Officer, and Chief Development Officer, 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, Mcf for natural gas, and barrels for NGL 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, 2017 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, 2017.
Below are estimates of our net proved reserves at December 31, 2017, all of which are located in Colorado:
The following tabulations present the PV-10 value of our estimated reserves as of December 31, 2017, 2016, and 2015 (in thousands):
The following table presents the prices used to prepare the reserve estimates, which are based on 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 year ended December 31, 2017, the combined effect of our drilling, acquisition, and participation activities and increased commodity prices generated an increase in projected future cash inflow from proved reserves of $3.3 billion and an increase in future pre-tax net cash flow of $2.2 billion from December 31, 2016 to December 31, 2017. During the same period, our PV-10 from proved reserves increased by $1.3 billion. During the year ended December 31, 2017, we incurred capital expenditures of approximately $600.0 million related to the acquisition and development of proved reserves.
During the year 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 year 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.
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, 2017, our proved undeveloped reserves were 139,315 MBOE. During 2017, the GCII Acquisition, along with other minor acquisitions, led to an increase of 34,867 MBOE in proved undeveloped reserves. This increase was partially offset by a decrease of 235 MBOE as a result of divestitures. In addition to the 23,781 MBOE of prior year proved undeveloped reserves converted to proved developed reserves, we added 46,913 MBOE of proved undeveloped reserves which were primarily attributable to extending our development plan by a year due to the passage of time as well as the addition of a third rig for the second and third years of our development plan. Further, due to a better commodity market environment, our increase in expected drilling activity positively affected our proved undeveloped reserves. Consistent with prior years, we limited our undeveloped locations related to horizontal wells to be drilled within this three-year horizon.
During the year end December 31, 2017, we converted 23,781 MBOE, or 32%, of our proved undeveloped reserves as of December 31, 2016 into proved developed reserves, requiring $185.2 million of drilling and completion capital expenditures. All proved undeveloped reserves as of December 31, 2017 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 midstream infrastructure buildout continues. None of our proved undeveloped reserves as of December 31, 2017 have been in this category for more than five years.
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 the creation of 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 GC Acquisition and related changes to our development plan that resulted in the removal of certain legacy PUD locations from the three-year drilling plan. This significant change to our development plan resulted in many of the legacy proved undeveloped locations being removed from the development plan. Consequently, only 806 MBOE, or 2%, of prior year proved undeveloped
reserves converted to proved developed reserves. During 2016, we also 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 assumed two rigs working continually throughout the three-year plan period.
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. Our proved undeveloped conversion rate for this four-month period is not comparable to the conversion rate for the full-year periods discussed above and below.
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. Our conversion rate during the fiscal year ended August 31, 2015 was affected by our focus at that time on delineation of our leasehold rather than immediate development. As discussed above, our development activities and conversion rate have increased significantly since that time.
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 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 to drill, complete, and work over wells in a timely and cost-effective manner.
The market for oil and natural gas is dependent upon a number of factors that are beyond our control and the effects of which are difficult to predict. 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, new legislation may be enacted that would impose price controls or additional excise taxes on oil, natural gas, or both. Oversupplies of oil and natural gas can be expected to occur from time to time and may result in, among other things, 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 1675 Broadway Suite 2600, Denver, CO 80202. Our office telephone number is (720) 616-4300, and our fax number is (720) 616-4301.
Our Greeley offices includes field offices and an equipment yard.
As of December 31, 2017, we had 122 full-time employees.
Available Information
We make available on our website, www.srcenergy.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.
Governmental 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 of 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. We are unable to predict the future costs or impact of compliance with applicable laws and regulations.
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 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 the leases do 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 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. These rules also require operator registration and/or notifications to local governments with respect to future oil and natural gas drilling and production facility locations. The COGCC also approved new rules in 2013, 2014 and 2015.
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 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. As a result, our sales of natural gas may be made at market prices, subject to applicable contract provisions. 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, but 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.
In August 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. The 2005 EPA directs the FERC 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, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or 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 or 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. This 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.
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.
Gathering is exempt from federal regulation under the NGA, but is subject to various state regulations, which include safety, environmental, and in some circumstances, nondiscriminatory take requirements. FERC has in the past reclassified transportation facilities previously considered to be subject to FERC jurisdiction as non-jurisdictional gathering facilities, and conversely, has also reclassified non-jurisdictional gathering facilities as subject to FERC jurisdiction. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.
Transportation and safety of natural gas is also subject to other federal and state laws and regulations, including regulation by the Department of Transportation under the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2012. The failure to comply with these rules and regulations can result in substantial penalties.
Our production and gathering facilities are not subject to jurisdiction of the FERC. Our natural gas sales prices, however, continue to be affected by intrastate and interstate gas transportation because the cost of transporting the natural gas once sold to the consuming market is a factor in the prices we receive, along with the availability and terms of such transportation. Competition among suppliers has greatly increased in recent years. Our natural gas sales are generally made at the prevailing market price at the time of sale.
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 transportation of oil, natural gas liquids 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 are subject to FERC regulation.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions in some jurisdictions. 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, and accordingly, 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.
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 exemptions 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 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 increased the potential penalties for violating the Colorado Oil and Gas Conservation Act or its implementing regulations, orders, or permits.
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. A proposed consent decree filed in December 2016 between the Environmental Protection Agency ("EPA") and certain environmental groups commits the EPA to deciding 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 (the “NSPS OOOOa”). 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. The EPA has proposed a two-year stay of the effective dates of several requirements of NSPS OOOOa. 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, Colorado adopted new and more stringent air quality control requirements. The Denver Metro/North Front Range NAA is at risk of being reclassified again to “serious” if it does not meet the 2008 NAAQS by 2018 or obtain an extension of the deadline from the EPA. A “serious” classification would trigger significant additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements becoming applicable to our operations and significant costs and delays in obtaining necessary permits. This process could result in new or more stringent air quality control requirements applicable to our operations.
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 rule has been stayed pending resolution of ongoing litigation. On January 31, 2018, the EPA signed a final rule delaying the applicability date of the “waters of the U.S.” for several years while the EPA continues to conduct a substantive re-evaluation of the definition of “waters of the U.S.”
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. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. 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 March 2017, President Trump signed the Executive Order on Energy Independence which, among other things, called for a review of the Clean Power Plan. The EPA subsequently published a proposed rule to repeal the Clean Power Plan in October 2017. A final rule is expected following a comment period.
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. In June 2017, President Trump announced that the United States would initiate the formal process to withdraw from the Paris Agreement.
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.
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, operators engaged in hydraulic fracturing 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 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. In March 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. The BLM rescinded the rule in December 2017; however, the BLM’s rescission has been challenged by several states in the United States District Court of the District of Northern California.
In November 2016, the 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 December 2017, the BLM published a rule to temporarily suspend or delay certain rule requirements until January 2019; that rule is also the subject of litigation in federal court.
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. 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 into memoranda of agreement with oil and gas producers to accomplish the same objective. In addition, during the past few years, five Colorado cities have passed voter initiatives temporarily or permanently prohibiting hydraulic fracturing. Local district courts have struck down the ordinances for certain of those Colorado cities, and these 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 generally, 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 2018 and in subsequent years. 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 securities. We do not make, nor have we authorized any other person to make, any representation about the future market value of our securities. In addition to the other information contained in this report, the following factors should be considered carefully in evaluating an investment in our securities. Except where the context indicates otherwise, substantially all of the risks described below relating to oil and natural gas and related activities apply to NGLs as well.
Risks Relating to Our Business and the Industry
A 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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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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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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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 and 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.
Sustained periods of reduced oil and natural gas prices and the resultant effect such prices have on our drilling economics and our ability to fund our operations could require us to re-evaluate and postpone or eliminate our development drilling, which would make it more difficult for us to achieve expected levels of production. Lower prices may also 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, which would likely result in a reduction in our proved undeveloped reserves and PV-10 and standardized measure values.
Lower oil and natural gas prices may also reduce our borrowing ability. Our borrowing capacity is based substantially on the value of our oil and natural gas reserves which are, in turn, impacted by prevailing oil and natural gas prices. Our actual borrowings may not exceed our borrowing base, which is currently $400 million. The next semi-annual redetermination of the borrowing base is scheduled to occur in April 2018. If our borrowing base were to decline significantly, we could 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.
We have historically relied on the availability of additional capital, including proceeds from the sale of equity, debt, and convertible securities, to execute our business strategy. Future acquisitions may require 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 future acquisition.
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 those underlying 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.
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 prior reserve reports. We cannot assure you that these differences will not be material in the future.
Approximately 61% of our estimated proved reserves at December 31, 2017 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 $982.9 million in estimated capital expenditures during the five years ending December 31, 2022. 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, 2017 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. 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 particular species as threatened or endangered could have a material adverse effect on our operations in areas where those 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.
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 GCII 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 generally consistent with industry practices, these reviews are inherently incomplete. It is typically 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 any 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 estimated reserves associated with 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 GCII 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.
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. Historically, we 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.
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 produce and/or 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 when pipeline interruptions occur due to scheduled or 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 reasons. 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 the systems we use 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 from time to time, and this has on occasion reduced capacity and caused gas production to be shut in. 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.
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 year ended December 31, 2017 was $(6.58) per barrel for oil and $(0.67) 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 ceiling test write-down 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, 2017 used average realized prices of $46.57 per barrel and $2.21 per Mcf. The oil price used at December 31, 2017 was approximately 29% higher than the December 31, 2016 price of $36.07 per barrel, and the gas price was approximately 9% lower than the December 31, 2016 price of $2.44 Mcf. In addition to our December 31, 2017 ceiling test calculation, we compare our net capitalized costs for oil and gas properties to the ceiling amount at various points during the year. At March 31, 2017, June 30, 2017, September 30, 2017, and December 31, 2017, the ceiling amount exceeded our net capitalized costs for oil and gas properties, and as such, no impairments were necessary. 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 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, laws, and regulations;
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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 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 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 four 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 three years. Since 2016, we have been obligated to deliver a combined volume of 11,157 Bbls of oil per day to three of these counterparties. We also committed to deliver 2,500 Bbls of oil per day to the fourth counterparty for approximately one and a half years beginning in the latter half of 2018. 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 $0.7 million during the year ended December 31, 2017.
Furthermore, in collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin. The first agreement includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed during the third quarter of 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 seven years. The second agreement also includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed in mid-2019, although the start-up date is undetermined at this time. Our share of the commitment will require 43.8 MMcf per day to be delivered after the plant in-service date for a period of seven years. These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' 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, new assets may not generate revenues comparable to our existing business, the anticipated cost efficiencies or synergies may not be realized, and the 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, including as a result of the actions of third parties.
We are affected significantly by a substantial number of governmental regulations relating to, among other things, the release or disposal of materials into the environment, health and safety, land use, and other matters. A summary of the principal environmental rules and regulations to which we are currently subject is set forth in “Business and Properties-Governmental Regulation-Environmental Regulations.” Compliance with such laws and regulations often increases our cost of doing business and thereby 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;
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require us to add procedures and/or staff in order to comply with applicable laws and regulations; and
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impose substantial liabilities for pollution resulting from our operations.
In addition, we could face liability under applicable environmental laws and regulations as a result of the activities of previous owners of our properties or other third parties. 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 our fault, whether we were responsible for the release or whether the operations at the time of the release were lawful.
Compliance with, or liabilities associated with violations of or remediation obligations under, environmental laws and regulations could have a material adverse effect on our results of operations and financial condition.
New or amended environmental legislation or regulatory initiatives could result in increased costs, additional operating restrictions, or delays or have other adverse effects on us.
The environmental laws and regulations to which we are subject change frequently, often to become more burdensome and/or to increase the risk that we will be subject to significant liabilities. New or amended 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.
For example, in 2014 and 2016, opponents of hydraulic fracturing sought statewide ballot initiatives in Colorado that would have restricted oil and gas development in Colorado and could have had materially adverse impacts on us. One of the proposed initiatives 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. Although none of the proposed initiatives were implemented, future initiatives are likely, including in 2018. Similarly, proposals are made from time to time to adopt new, or amend existing, laws and regulations to address hydraulic fracturing or climate change concerns through further regulation of exploration and development activities. The “Business and Properties-Governmental Regulation-Environmental Matters” section of this report includes a discussion of some recent environmental regulatory changes that have affected us. We cannot predict the nature, outcome, or effect on us of future regulatory initiatives, but such initiatives could materially impact our results of operations, production, reserves, and other aspects of our business.
The adoption and implementation of 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 the elimination of the immediate deduction for intangible drilling and development costs, the elimination of the deduction from income for domestic production activities relating to oil and gas exploration and development, the repeal of the percentage depletion allowance for oil and gas properties, and an extension of the amortization period for certain geological and geophysical expenditures. Such changes, 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, 2017, the aggregate amount of our outstanding indebtedness was $550 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; 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 the holders of our securities. 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 2025 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. 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 applicable 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 is also 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 management 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 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 year ended December 31, 2017, we had three major customers, which represented 33%, 24%, and 17%, respectively, 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.
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 GCII 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, 2017, we operated 227 gross horizontal producing wells, with an additional 51 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 new 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, unfavorable commodity prices, or other factors, 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:
•
changes in production volumes, worldwide demand and prices for oil and natural gas;
•
changes in market prices of oil and natural gas;
•
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;
•
changes in market valuations of similar companies;
•
changes in interest rates;
•
announcements regarding adverse timing or lack of success in discovering, acquiring, developing, and producing oil and natural gas resources;
•
announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments;
•
decreases in the amount of capital available to us;
•
operating results that fall below market expectations or variations in our quarterly operating results;
•
loss of a relationship with a partner;
•
the identification of and severity of environmental events and governmental and other third-party responses to the events; or
•
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, are also 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.
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 prices.
Equity compensation plans will result in 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, 2017, there were 8,738,146 shares reserved for issuance under our equity compensation plans, of which 1,087,386 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, 951,884 performance-vested 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 5,636,834 of which are issuable upon the exercise of outstanding options to purchase common stock. Our outstanding options have a weighted average exercise price of $9.38 per share as of December 31, 2017.
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
In July 2016, the Company was informed by the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division ("CDPHE") that it was expanding its review 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. Subsequent tolling agreements between the Company and CDPHE addressed alleged similar storage tank leakage issues at other Company facilities in Colorado. On February 21, 2018, the Company and CDPHE entered into a Compliance Order on Consent resolving the issues related to leakage of volatile organic compounds at certain of the Company’s facilities in Colorado. The terms of the order do not have a material effect on the Company.
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 American under the symbol “SRCI.”
Shown below is the range of high and low sales prices for our common stock as reported by the NYSE American for the past two years.
As of February 19, 2018, the closing price of our common stock on the NYSE MKT was $8.92.
As of February 19, 2018, we had 241,786,159 outstanding shares of common stock and 80 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, 2017, 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, 2012 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 Adjusted to include the effect of transportation and gathering expenses.
2 Depletion, Depreciation, & Accretion
As of January 1, 2017, our natural gas processing agreements with DCP Midstream have been modified to allow us to take title to the NGLs resulting from the processing of our natural gas. Based on this, we began reporting reserves, sales volumes, prices, and revenues for natural gas and NGLs separately for periods after January 1, 2017. For periods prior to January 1, 2017, we did not separately report reserves, sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of 2017 with prior periods.
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, 2017, and its results of operations for the years ended December 31, 2017, December 31, 2016, and December 31, 2015 (unaudited). 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.
As of January 1, 2017, our natural gas processing agreements with DCP Midstream were modified to allow us to take title to the NGLs resulting from the processing of our natural gas. Based on this, we began reporting reserves, sales volumes, prices, and revenues for natural gas and NGLs separately for periods after January 1, 2017. For periods prior to January 1, 2017, we did not separately report reserves, sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of 2017 with prior periods.
Overview
SRC Energy Inc. is an independent oil and gas company engaged in the acquisition, development, and production of oil, natural gas, and NGLs 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 formation as well as the three benches of the Niobrara formation, which are all 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 78% 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, natural gas, and NGLs 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 fiscal years.
For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices) as well as the differential between the Reference Price and the prices realized by us.
* Adjusted to include the effect of transportation and gathering expenses.
Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The differential between the prices 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 oil, substantially all of the Company's first quarter 2017 oil production was sold to the counterparties of its firm sales commitments. Beginning in the second quarter of 2017, the Company's oil production exceeded its firm sales commitments, and the surplus oil production was sold at a reduced differential as compared to our committed volumes. Relating to the sale of natural gas, prior to January 1, 2017, the price we received included payment for a percentage of the value attributable to the natural gas liquids produced with the natural gas. Beginning in the first quarter of 2017, natural gas liquids and dry natural gas volumes are disclosed separately, and NGL revenues will replace the premium to dry natural gas prices that the Company historically realized on its wet natural gas sales volumes.
There has been significant volatility in the price of oil and natural gas since mid-2014. During the year ended December 31, 2017, the NYMEX-WTI oil price ranged from a high of $60.46 per Bbl on December 29, 2017 to a low of $42.48 per Bbl on June 21, 2017, and the NYMEX-Henry Hub natural gas price ranged from a low of $2.56 per MMBtu on February 21, 2017 to a high of $3.42 per MMBtu on May 12, 2017. As reflected in published data, the price for WTI oil settled at $53.75 per Bbl on Friday, December 30, 2016. Comparably, the price of oil settled at $60.46 per Bbl on Friday, December 29, 2017, an increase of 12% from December 31, 2016. 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, natural gas, and NGL 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 impact the calculation of the “ceiling test” required under the accounting principles for companies following the “full cost” method of accounting. At December 31, 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. However, if pricing conditions decline, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters.
Core Operations
The following table provides details about our ownership interests with respect to vertical and horizontal producing wells as of December 31, 2017:
In addition to the producing wells summarized in the preceding table, as of December 31, 2017, we were the operator of 51 gross (47 net) wells in progress, which excludes 19 gross (16 net) wells for which we have only set surface casings. As of December 31, 2017, we are participating in 35 gross (6 net) non-operated horizontal wells in progress.
As we develop our acreage through horizontal drilling, we have an active program for plugging and abandoning the vast majority of the operated vertical wellbores. During the year ended December 31, 2017, we plugged 159 wells and returned the associated surface acreage to the property owners.
Properties
As of December 31, 2017, our estimated net proved oil and natural gas reserves, as prepared by Ryder Scott, were 69.4 MMBbls of oil and condensate, 559.9 Bcf of natural gas, and 64.0 MMBbls of natural gas liquids. As of December 31, 2017, we had approximately 98,600 gross and 88,300 net acres under lease in the Wattenberg Field. We also have non-core leasehold in other areas of Colorado and southwest Nebraska approximating 238,500 gross and 200,500 net acres.
Production
For the year ended December 31, 2017, our average net daily production increased to 34,194 BOED as compared to 11,670 BOED for the year ended December 31, 2016. By comparison, our production increased from 9,548 BOED for the year ended December 31, 2015 to 11,670 BOED for the year ended December 31, 2016. As of December 31, 2017, approximately 98% of our daily production was from horizontal wells.
Significant Developments
Acquisitions
In December 2017, the Company completed the purchase of a total of approximately 30,200 net acres in the Greeley-Crescent development area in Weld County Colorado, primarily south of the city of Greeley, for $569.5 million, comprised of $568.1 million in cash and the assumption of certain liabilities ("GCII Acquisition"). Estimated net daily production from the acquired non-operated properties was approximately 2,500 BOE at the time we entered into the agreement governing the transaction (the "GCII Agreement"). The effective date of this part of the transaction was November 1, 2017. The GCII Agreement also contemplates a second closing at which we will acquire operated producing properties subject to certain regulatory restrictions. The purchase price payable at the second closing will be determined based on the amount of then-current production from the properties conveyed and is expected to be completed in 2018. For the second closing, the effective date will be the first day of the calendar month in which the closing for such properties occurs. 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.
In September 2017, we completed the second closing contemplated by the purchase and sale agreement (the "GC Agreement") relating to our 2016 acquisition of approximately 33,100 net acres in the Greeley-Crescent area for $505 million (the "GC Acquisition"). At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. The purchase and sale agreement for the GC Acquisition was signed in May 2016 and the first closing was
completed in June 2016. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company. The total purchase price for the second closing was $30.3 million, composed of cash of $6.3 million and assumed liabilities of $24.0 million. The assumed liabilities included $20.9 million for asset retirement obligations.
In August 2017, we entered into an agreement with another party to trade approximately 3,200 net acres of the Company's non-contiguous acreage for approximately 3,200 net acres within the Company's core operating area. This transaction closed in the fourth quarter of 2017. We also executed a purchase and sale agreement with a private party for the acquisition of approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million, composed of cash and assumed liabilities.
In March 2017, we acquired developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.1 million, composed of cash and assumed liabilities.
Divestitures
During the year ended December 31, 2017, we completed divestitures of approximately 16,000 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $91.6 million in cash and the assumption by the buyers of $5.2 million in asset retirement obligations and $22.2 million in other liabilities. In accordance with full cost accounting guidelines, the net proceeds were credited to the full cost pool.
Equity Offering
In November 2017, the Company, in connection with a registered underwritten public offering of its common stock (the “Offering”), entered into an underwriting agreement (the “Underwriting Agreement”) with the several underwriters named therein (the “Underwriters”) and pursuant to which the Company agreed to sell 35,000,000 shares of its common stock to the Underwriters at a price of $7.76 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 5,250,000 shares of common stock on the same terms and conditions. The option was exercised in full on November 10, 2017, bringing the total number of shares issued in the Offering to 40,250,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $312.2 million. The Company used the proceeds of the offering to pay a portion of the purchase price of the GCII Acquisition and to repay amounts borrowed under the Revolver.
Revolving Credit Facility
In September 2017, the lenders under the Revolver completed their regular semi-annual redetermination of our borrowing base. The borrowing base was increased from $225 million to $400 million. The next semi-annual redetermination is scheduled for April 2018. Due to the outstanding principal balance and letters of credit, approximately $399.5 million of the borrowing base was available to use for future borrowings as of December 31, 2017, subject to our covenant requirements.
2025 Senior Notes
In November 2017, the Company issued $550 million aggregate principal amount of the 2025 Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 (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 2025 Senior Notes were $538.1 million after deductions of $11.9 million for expenses and underwriting discounts and commissions. The net proceeds were used to fund the GCII Acquisition, repay the 2021 Senior Notes, and pay off the outstanding Revolver balance. 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.
2021 Senior Notes
In December 2017, the Company repurchased all $80 million aggregate principal amount of its 2021 Senior Notes. At the time of repurchase, the Company made a required make whole payment of $8.2 million and wrote-off deferred issuance costs of $3.6 million.
Drilling and Completion Operations
Our drilling and completion schedule drives our production forecast and our expected future cash flows. 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. Should commodity prices weaken or our costs escalate significantly, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If the well-level internal rate of return is 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 completion activities.
During the year ended December 31, 2017, we drilled 115 operated horizontal wells and turned 109 operated horizontal wells to sales. As of December 31, 2017, we are the operator of 51 gross (47 net) horizontal wells in progress, which excludes 19 gross (16 net) horizontal wells for which we have only set surface casings. For 2018, we expect to drill 117 gross (100 net) operated horizontal wells and complete approximately 116 gross (103 net) operated horizontal wells with mostly mid-length and long laterals targeting the Codell and Niobrara zones.
For the year ended December 31, 2017, we participated in the completion activities on 63 gross (11 net) non-operated horizontal wells. As of December 31, 2017, we are participating in 35 gross (6 net) non-operated horizontal wells in progress. The Company is actively conveying its interests in many of the underlying non-operated wells in progress through signed or anticipated agreements.
Trends and Outlook
Oil traded at $53.75 per Bbl on December 30, 2016, but has since increased approximately 12% as of December 29, 2017 to $60.46. Natural gas traded at $3.72 per Mcf on December 30, 2016, but declined approximately 21% as of December 29, 2017 to $2.95. Although oil prices have increased in the second half of 2017, they continue to be volatile and are out of our control. If oil prices decrease, this could (i) reduce our cash flow which, in turn, could reduce the funds available for exploring and replacing oil and natural gas reserves, (ii) reduce our 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) reduce the number of oil and gas prospects which have reasonable economic returns, (iv) 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) result in marginally productive oil and natural gas wells being abandoned as non-commercial, and (vi) 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) the availability and capacity of gathering systems, pipelines, and other midstream infrastructure for our production, (iv) our ability to satisfy our financial and volume commitment obligations, (v) completion of acquisitions of additional properties and reserves, and (vi) competition from other oil and gas companies.
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 we believe that it is too early to determine whether the recoveries justify the additional capital cost.
We have been able to reduce drilling and completion costs due to a combination of optimizing well designs, fewer average days to drill, and lower completion costs. This focus on cost reduction has supported well-level economics giving consideration to the current 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.
Midstream companies that operate the natural gas processing facilities and gathering pipelines in the Wattenberg Field continue to make significant capital investments to increase the capacity of their systems. From time to time, our production has been adversely impacted by the lack of processing capacity resulting in high natural gas gathering line pressures.
To address the growing volumes of 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 support the expansion of natural gas gathering and processing capacity through agreements that impose baseline and incremental volume commitments, which we are currently exceeding. 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 during the third quarter of 2018. Additionally, through the same framework, all of the parties agreed to a development plan to add another 200 MMcf/d plant in mid-2019.
We have extended the use of oil and water gathering lines to certain production locations. These gathering systems are owned and operated by independent third parties, and we commit specific leases or areas to these systems. We believe these gathering lines have several benefits, including a) reduced need to use trucks, thereby reducing truck traffic and noise in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) reduced on-site storage capacity, resulting in lower production location facility costs, and d) generally improved community relations. As these gathering lines are currently being expanded, we have experienced and expect to continue to experience some delays in placing our pads on production.
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. We strive to reduce the negative differential that we have historically realized on our oil production depending on transportation commitments, local refinery demand, and our production volumes. Further details regarding posted prices and average realized prices are discussed in "-Market Conditions."
As of December 31, 2017, we have identified over 1,700 drilling locations across our acreage position in the core of the Wattenberg Field. For 2018, we expect to drill 117 gross operated horizontal wells with mostly mid-length and long laterals targeting the Codell and Niobrara zones. We anticipate this drilling and completion program will cost between $480 million and $540 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 2018 production to average between 48,000 BOED and 52,000 BOED with oil making up 47% - 50% of production.
Other than the foregoing, we do not know of any trends, events, or uncertainties that have had, during the periods covered by this report, 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, 2017 compared to the year ended December 31, 2016
For the year ended December 31, 2017, we reported net income of $142.5 million compared to net loss of $219.2 million during the year ended December 31, 2016. Net income per basic and diluted share was $0.69 for the year ended December 31, 2017 compared to net loss per share per basic and diluted share of $1.26 for the year ended December 31, 2016. Net income per basic share for the year ended December 31, 2017 increased by $1.95 primarily due to the ceiling test impairment of $215.2 million incurred during the year ended December 31, 2016 (whereas no ceiling test impairment was recognized during the year ended December 31, 2017) and the 238.3% increase in revenues period over period as described below.
Oil and Natural Gas Production and Revenues - For the year ended December 31, 2017, we recorded total oil, natural gas, and NGL revenues of $362.5 million compared to $107.1 million for the year ended December 31, 2016, an increase of $255.4 million or 238%. The following table summarizes key production and revenue statistics:
1 For periods prior to January 1, 2017, we did not separately report sales volumes, prices, and revenues for NGLs as we did not take title to these NGLs. Instead, the value attributable to these unrecognized NGL volumes was included within natural gas revenues as an increase to the overall price received. This change impacts the comparability of the two periods presented.
2 Adjusted to include the effect of transportation and gathering expenses.
Net oil, natural gas and NGL production for the year ended December 31, 2017 averaged 34,194 BOED, an increase of 193% over average production of 11,670 BOED in the year ended December 31, 2016. From December 31, 2016 to December 31, 2017, our well count increased by 140 net horizontal wells, growing our reserves and daily production totals. Additionally, our conversion to three stream accounting positively impacted reported production in the current period. The 192% increase in production and the 15% increase in average sales prices resulted in a significant increase in 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 and type of wells and our overall production volumes and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas. During the year ended December 31, 2017, we experienced decreased production expense compared to the year ended December 31, 2016 primarily due to significantly less expense related to environmental remediation and regulatory compliance projects during 2017 and the continued consolidation of our operations into a more central geographic operating area. Unit operating costs benefited from larger volumes of early production on the 101 net horizontal wells turned to sales during the
year ended December 31, 2017.
Transportation and gathering - During 2017, the Company entered into new gathering agreements which resulted in new transportation and gathering charges. Transportation and gathering was $3.2 million, or $0.26 per BOE, for the year ended December 31, 2017, compared to nil for the year ended December 31, 2016. While reported as an expense, the Company analyzes these charges on a net basis within revenue.
Production taxes - Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. Production taxes were $36.3 million, or $2.91 per BOE, for the year ended December 31, 2017, compared to $5.7 million, or $1.34 per BOE, for the year ended December 31, 2016. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were 10.0% and 5.3% for the years ended December 31, 2017 and 2016, respectively. During the year ended December 31, 2017, the Company adjusted its estimates for production taxes to reflect significant increases in production. During the year ended December 31, 2016, the Company reduced its estimate for ad valorem taxes, 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, 2017, DD&A was $9.00 per BOE compared to $10.93 per BOE for the year ended December 31, 2016. 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 increase in our total proved reserves and the impairments of our full cost pool that primarily occurred during 2016. These impacts were partially offset by recent drilling and completion activities which increased the amortization base. 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 determined the depletion rate.
Full cost ceiling impairment - During the year ended December 31, 2017, we had no impairment as compared to an impairment of $215.2 million for the year ended December 31, 2016, 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. Total G&A costs of $33.0 million for the year ended December 31, 2017 were 8% higher than G&A for the year ended December 31, 2016. This increase is primarily due to a 27% increase in employee headcount from 96 at December 31, 2016 to 122 at December 31, 2017, which was offset by a reduction in professional fees incurred due to decreased contract services during 2017.
Our G&A expense for the year ended December 31, 2017 includes stock-based compensation of $11.2 million compared to $9.5 million for the year ended December 31, 2016.
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, 2016 to the year ended December 31, 2017 reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.
Commodity derivatives - 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 volatility of oil and natural gas prices. For the year ended December 31, 2017, we realized a cash settlement gain of $39.0 thousand, net of previously incurred premiums attributable to the settled commodity contracts. In 2016, we realized a cash settlement gain of $2.4 million.
In addition, for the year ended December 31, 2017, we recorded an unrealized loss of $4.3 million to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the year ended December 31, 2016, we reported an unrealized loss of $10.1 million. Unrealized losses are non-cash items.
Income taxes - We reported income tax benefit of $0.1 million for the year ended December 31, 2017, calculated at an effective tax rate of 0%. In 2016, we reported income tax expense of $0.1 million, calculated at an effective tax rate of 0%. As explained in more detail below, during the year ended December 31, 2017, 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, 2017. During 2016, we reached the same conclusion; therefore, a valuation allowance has been provided as of December 31, 2016.
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, natural gas, and NGL 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 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.”
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. We increased our employee count from 62 at December 31, 2015 to 96 at December 31, 2016, 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 volatility of oil and natural gas prices. 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.
Liquidity and Capital Resources
Historically, our primary sources of capital have been net cash provided by cash flow from operations, proceeds from the sale of properties, the sale of equity and debt securities, 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, 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. 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. Oil and gas 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, 2017, we had cash, cash equivalents, and restricted cash of $48.8 million, $550.0 million outstanding on our 2025 Senior Notes, and no balance outstanding under our revolving credit facility. Our sources and (uses) of funds for the years ended December 31, 2017, 2016, and 2015 are summarized below (in thousands):
Net cash provided by operating activities was $291.3 million, $48.7 million, and $103.8 million for the years ended December 31, 2017, 2016, and 2015, respectively. The increase in cash from operating activities from the year ended December 31, 2016 to the year ended December 31, 2017 reflects the increase in realized commodity prices and production.
Net cash provided by other investing activities was $93.6 million, $25.4 million, and $6.2 million for the years ended December 31, 2017, 2016, and 2015, respectively. For the year ended December 31, 2017, we received proceeds from the sale of oil and gas properties and other of $93.6 million. For the year ended December 31, 2016, we received proceeds from the sale of oil and gas properties of $25.4 million.
Net cash provided by equity financing activities was $312.3 million, $542.7 million, and $187.4 million for the years ended December 31, 2017, 2016, and 2015, respectively. Net cash provided by (used in) debt financing activities was $448.6 million, $(3.2) million, and $(68.0) million for the years ended December 31, 2017, 2016, and 2015, respectively. During the year ended December 31, 2017, we received cash proceeds from borrowing $250 million under the Revolver which were primarily used to fund our drilling and completion activities. Additionally, we issued $550 million aggregate principal amount of 2025 Senior Notes in a private placement to qualified institutional buyers. See " - 2025 Senior Notes." The net proceeds from the sale of the 2025 Senior Notes were $538.1 million after deductions of $11.9 million for expenses and underwriting discounts and commissions. Lastly, we received cash proceeds of approximately $312.2 million (after deduction of underwriting discounts and expenses payable by the Company) from our public offering of 40,250,000 shares (including the shares sold pursuant to an over-allotment option exercised by the underwriters) at a price to us of $7.76. The proceeds from the private placement and the public offering were used to repay $250 million of borrowings under the Revolver, fund the GCII Acquisition, and repay the $80 million aggregate principal amount of the 2021 Senior Notes.
Credit Facility
The Revolver has a maturity date of December 15, 2019. The agreement was most recently amended in September 2017 as a result of the regular semi-annual redetermination of our borrowing base. The Revolver has 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 Revolver. The value of the collateral will generally be derived with reference to the estimated discounted future net cash flows from our proved oil and natural gas reserves. The collateral includes substantially all of our producing wells and developed oil and gas leases.
As a result of the regular semi-annual redetermination of our borrowing base on September 27, 2017, the borrowing base was increased from $225 million to $400 million. As of December 31, 2017, there was no outstanding principal balance and $0.5 million in letters of credit outstanding, leaving $399.5 million available to us for future borrowings. The next semi-annual redetermination is scheduled for April 2018. Interest on the Revolver 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. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the end of any fiscal quarter 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.
2025 Senior Notes
In November 2017, the Company issued $550 million aggregate principal amount of 6.25% Senior Notes in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 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. At any time prior to December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to 100% of the principal amount plus an Applicable Premium (as defined in the Indenture) plus accrued and unpaid interest. On and after December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at the redemption price equal to a specified percentage of the principal amount of the redeemed notes (104.688% for 2020, 103.125% for 2021, 101.563% for 2022, and 100% for 2023 and thereafter, during the twelve-month period beginning on December 1 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 1, 2020, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the 2025 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 106.25% 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.
2021 Senior Notes
In December 2017, the Company repurchased all $80 million aggregate principal amount of its 2021 Senior Notes. At the time of repurchase, the Company made a required make whole payment of $8.2 million and wrote-off deferred issuance costs of $3.6 million.
Capital Expenditures
Capital expenditures for drilling and completion activities totaled $461.8 million, $130.9 million, and $127.8 million for the year ended December 31, 2017, 2016, and 2015, respectively. The following table summarizes our capital expenditures for oil and gas properties (in thousands):
* Capital expenditures for drilling and completion activities exclude $34.9 million of expenditures that were accrued during the year ended December 31, 2017; however, the properties associated with these expenditures were subsequently traded, and no cash was required to be remitted to the operator of the activities.
**Acquisitions of oil and gas properties and leasehold reflects the full purchase price of our various acquisitions which includes non-cash additions for liabilities assumed in the transaction such as asset retirement obligations.
***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 GCII Acquisition, the majority of capital expenditures during the year ended December 31, 2017 were associated with the costs of drilling and completing wells. During the year ended December 31, 2017, we drilled 115 operated horizontal wells and turned 109 operated horizontal wells to sales. As of December 31, 2017, we are the operator of 51 gross (47 net) horizontal wells in progress, which excludes 19 gross (16 net) wells for which we have only set surface casings. All of the wells in progress at December 31, 2017 are scheduled to commence production before December 31, 2018.
For the year ended December 31, 2017, we participated in 35 gross (6 net) non-operated horizontal wells.
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, development results, and downstream commitments, 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 2018.
We anticipate that our 2018 drilling and completion capital expenditures for operated wells will cost between $480 million and $540 million for the year. However, 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. However, should this not meet all of our long-term needs, 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. We may seek to raise funds in capital markets transactions from time to time if we believe market conditions to be favorable.
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 December 31, 2017, we had open positions covering 3.7 million barrels of oil and 5,475 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 premiums paid for the contracts 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, 2017, we reported an unrealized commodity activity loss of $4.3 million. Unrealized losses are non-cash items. We also reported a realized gain of $39.0 thousand, 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, 2017, we estimated that the fair value of our various commodity derivative contracts was a net liability of $7.9 million. See Note 8, Commodity Derivative Instruments, for a description of the methods we use to estimate the fair values of commodity derivative instruments.
Contractual Commitments
The following table summarizes our contractual obligations as of December 31, 2017 (in thousands):
Represents an estimate of the commitment related to the use of two rigs. 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 $5.21 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 agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin under two agreements. For the first agreement, our share of the commitment will require 46.4 MMcf per day to be delivered after the plant in-service date, which is currently expected to be during the third quarter of 2018, for a period of 7 years. For the second agreement, our share of the commitment will require 43.8 MMcf per day to be delivered after the plant in-service date, which is expected to be
completed in mid-2019, for a period of 7 years. These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment. While we expect that our development plan will support the utilization of this capacity, 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 2025 Senior Notes. 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"). The following is a summary of the measures we currently report.
Adjusted EBITDA
We use "adjusted EBITDA," a non-GAAP financial measure, for internal managerial purposes because it allows us to 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 income (loss) in arriving at adjusted EBITDA. We exclude those items because they 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. Adjusted EBITDA is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, net income. We believe that adjusted EBITDA is 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. However, our definition of adjusted EBITDA may not be fully comparable to measures with similar titles reported by other companies. We define adjusted EBITDA as net income (loss) adjusted to exclude the impact of the items set forth in the table below (amounts in thousands):
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:
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, 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairments were necessary. A 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 ceiling test impairments in future periods.
Oil, Natural Gas, and NGL 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, natural gas, and NGL revenues partially offset realized gains in our hedge transactions. During any reporting period in which 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 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 calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, the Company should recognize an impairment charge. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill. We performed our annual goodwill impairment test as of October 1, 2017. This test did not result in an impairment. 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 72% of our revenue during year ended December 31, 2017 was from the sale of oil. A $5 per barrel change in our realized oil price would have resulted in a $29.1 million change in revenues for the year ended December 31, 2017, a $0.25 per Mcf change in our realized natural gas price would have resulted in a $6.2 million change in our natural gas revenues, and a $5 per barrel change in our realized NGL price would have resulted in a $12.6 million change in our NGL revenues for the year ended December 31, 2017.
During the year ended December 31, 2017, the price of oil, natural gas, and NGLs increased relative to the year ended 2016. 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, natural gas, and NGL 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, natural gas, and NGLs prices with any degree of certainty. Sustained weakness in oil, natural gas, and NGL prices may adversely affect our financial condition and results of operations and may also reduce the amount of oil, natural gas, and NGL reserves that we can produce economically. Any reduction in our oil, natural gas, and NGL 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, natural gas, and NGL 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. Under the Revolver, we can 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, 2017, we had open oil and natural gas derivatives in a net liability position with a fair value of $7.9 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 $9.0 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 $3.8 million.
Interest Rate Risk - At December 31, 2017, we had no debt outstanding under our revolving credit facility. Interest on our credit facility accrues at a variable rate, based upon either the Prime Rate or LIBOR plus an applicable margin. During the year ended December 31, 2017, we incurred interest at an annualized rate of 3.4%. We are exposed to interest rate risk on the credit facility if the variable reference rates increase. 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% for the year ended December 31, 2017, our interest payments would have changed by approximately $0.6 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 due to restrictions imposed by the Revolver.
Counterparty Risk - As described in "- Commodity Price Risk" above, 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.
We believe that our exposure to counterparty risk increased slightly during the year ended December 31, 2017 as the amounts due to us from counterparties has increased.
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, 2017 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, 2017.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2017, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which appears herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of SRC Energy Inc.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of SRC Energy Inc. and subsidiaries (the “Company”) as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2017, of the Company and our report dated February 21, 2018, expressed an unqualified opinion on those financial statements.
Basis for Opinion
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 are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed 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 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.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 21, 2018
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, 2017, pursuant to Regulation 14A under the Exchange Act (the “2018 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 2018 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 2018 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 2018 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 2018 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
SRC ENERGY INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of SRC Energy Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of SRC Energy Inc. and subsidiaries (the "Company") as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in shareholders' equity, and cash flows, for each of the two years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017, 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) (PCAOB), the Company's internal control over financial reporting as of December 31, 2017, 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 21, 2018, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 21, 2018
We have served as the Company's auditor since 2016.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
SRC Energy Inc.
Denver, Colorado
We have audited the accompanying consolidated balance sheet of SRC Energy Inc. (formerly known as Synergy Resources Corporation) 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 the year 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 SRC Energy Inc. 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 the year ended August 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ EKS&H LLLP
April 22, 2016
Denver, Colorado
SRC ENERGY INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements
SRC ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)
The accompanying notes are an integral part of these consolidated financial statements
SRC ENERGY INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(in thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements
SRC ENERGY INC.
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
SRC ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017, 2016 and 2015, and August 31, 2015
1.
Organization and Summary of Significant Accounting Policies
Organization: SRC Energy Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and NGLs, primarily in the D-J Basin of Colorado. On June 15, 2017, our shareholders approved an amendment to the Amended and Restated Articles of Incorporation of the Company to change the name of the Company from Synergy Resources Corporation to SRC Energy Inc. The Company had been using the new name on a "doing business as" basis since March 6, 2017. In addition to using the new name, the Company’s common stock, which is listed and traded on the NYSE American, changed to the new symbol "SRCI."
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 ("SEC") to use "plain English" in public filings, the Company will use such terms as "we," "our," "us," or the "Company" in place of SRC Energy Inc. When such terms are used in this manner throughout this document, they are in reference only to the corporation, SRC Energy Inc., 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 subsidiaries. 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 had placed $18.2 million in escrow, which was released upon the second closing of the GC Acquisition. Please refer to Note 3, Acquisitions and Divestitures, for further information.
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the consolidated statements of cash flows:
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, 2017, the Company did not recognize any ceiling test impairments. During the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, the Company recognized ceiling test impairments of $215.2 million, $125.2 million, and $16.0 million, respectively.
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, office furniture and equipment, and buildings are 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, office leasehold improvements, and office furniture and equipment are depreciated under the straight-line method using estimated useful lives ranging from three to five years. Buildings are also depreciated under the straight-line method using estimated useful lives of thirty-nine 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 other property and 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 ("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 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. Asset retirement costs ("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 FASB Accounting Standards Codification ("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 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 calculate the estimated fair value of the reporting unit. If the carrying value of the reporting unit exceeds the estimated fair value, the Company should recognize an impairment charge. The amount of impairment for goodwill is measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill. For purposes of assessing goodwill, the Company only has one reporting unit.
We performed our annual goodwill impairment test as of October 1, 2017. This test did not result in an impairment. 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, Natural Gas, and NGL Revenues: The Company derives revenue primarily from the sale of oil, natural gas, and NGLs 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 product 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, natural gas, and NGL 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, the multiple contracts for sales of our products, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that the loss of our existing customers or individual contract would not have a material adverse effect on us. Our oil and natural gas production is a commodity with a readily available market, and we sell our products under many distinct contracts. In addition, there are several oil and natural gas purchasers and processors within our area of operations to whom our production could be sold.
Accounts receivable consist primarily of receivables from oil, natural gas, and NGL 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 (these companies do not necessarily correspond to those presented above):
* 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, 2017. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of December 31, 2017, 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 gain (loss) 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:
In November 2016, the FASB issued Accounting Standards Update ("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. We adopted this pronouncement effective October 1, 2017 and have applied it retrospectively. Upon adoption, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2016. This change resulted in a decrease to net cash used in investing activities of $18.2 million. Additionally, we removed cash held in escrow of $18.2 million from the statement of cash flows for the year ended December 31, 2017. This change resulted in an increase to net cash used in investing activities of $18.2 million. The adoption of this standard did not impact cash flows for the 4-months ended December 31, 2015 nor the year ended August 31, 2015. We have included a tabular reconciliation of cash, cash equivalents, and restricted cash in the discussion of "Cash Held in Escrow" above.
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 adopted this pronouncement effective January 1, 2017. Upon adoption of this standard, we no longer estimate the total number of awards for which the requisite service period will not be rendered, and effective January 1, 2017, we began accounting for forfeitures when they occur. We applied this accounting change on a modified retrospective basis with a cumulative-effect adjustment of $0.1 million to retained earnings as of the date of adoption. The adoption of the other provisions did not materially impact the consolidated financial statements.
In January 2017, the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment" ("ASU 2017-04"), which removes the requirement to compare the implied fair value of goodwill with its carrying amount as part of step 2 of the goodwill impairment test. We adopted ASU 2017-04 on January 1, 2017, and it will be applied for any interim or annual goodwill impairment tests subsequent to that date. The adoption of this guidance did not impact the consolidated financial statements.
Recently Issued Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us.
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. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International
Financial Reporting Standards. The FASB subsequently issued various ASUs, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU 2014-09 and its amendments are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The Company will adopt these ASUs with an effective date of January 1, 2018, using the modified retrospective method. While we have not yet completed all aspects of the adoption of the standard, based on our current assessment of contracts with customers, we do not believe there will be any impact to the timing of our revenue recognition or our operating income (loss), net income (loss), and cash flows. The Company is in the process of evaluating changes, if any, to accounting policies and internal control procedures along with continuing to assess additional disclosures which may be required upon implementation of these ASUs.
There were various updates recently 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. At December 31, 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. During the year ended December 31, 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, the Company's ceiling tests resulted in total impairments of $215.2 million, $125.2 million, and $16.0 million, respectively. No impairments were recognized for the comparable 2017 period.
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 an annual basis, or more frequently if necessary, for impairment and, if impaired, are reclassified to proved properties and included in the depletion base. During the year ended December 31, 2017, these reviews indicated that the estimated fair value of such assets exceeded the carrying values. Therefore, no impairment was necessary as December 31, 2017. However, during the years ended December 31, 2016 and August 31, 2015, the Company recorded impairments of $18.9 million and $15.4 million, respectively, related to the fair value of its unproved properties. No such impairments were recognized during the four months ended December 31, 2015.
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 expenditures, 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, 2017 (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 in the core Wattenberg Field to provide additional mineral acres upon which the Company can drill wells and produce hydrocarbons.
December 2017 Acquisition
In November 2017, the Company entered into an agreement ("GCII Agreement") to purchase a total of approximately 30,200 net acres located in an area known as the Greeley-Crescent development area in Weld County Colorado, primarily south of the city of Greeley, for $568 million ("GCII Acquisition"). Estimated net daily production from the acquired non-operated properties was approximately 2,500 BOE at the time we entered into the agreement. On December 15, 2017, 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 November 1, 2017, and the purchase price was $569.5 million, comprised of $568.1 million in cash and the assumption of certain liabilities. The purchase price has preliminarily been allocated as $59.9 million to proved oil and gas
properties and $509.6 million to unproved oil and gas properties, pending the final closing. The second closing will cover the operated producing properties and is expected to be completed in 2018. For the second closing, the effective date will be the first day of the calendar month in which the closing for such properties occurs. 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 was accounted for as an asset acquisition under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date of December 15, 2017.
September 2017 Acquisition
In September 2017, we completed the second closing of the GC Acquisition (as defined in "-June 2016 Acquisition" below). At the second closing, we acquired 335 operated vertical wells and 7 operated horizontal wells. The effective date of the second closing was April 1, 2016 for the horizontal wells acquired and September 1, 2017 for the vertical wells acquired. At the second closing, the escrow balance of $18.2 million was released and $11.4 million of that amount was returned to the Company. The total purchase price for the second closing was $30.3 million, composed of cash of $6.3 million and assumed liabilities of $24.0 million. The assumed liabilities included $20.9 million for asset retirement obligations. The entire purchase price has been allocated to proved oil and gas properties.
August 2017 Acquisition and Swap
In August 2017, we also entered into an agreement with another party to trade approximately 3,200 net acres of the Company's non-contiguous acreage for approximately 3,200 net acres within the Company's core operating area. This transaction closed in the fourth quarter of 2017. We also acquired approximately 1,000 net acres of developed and undeveloped leasehold and mineral interests, along with the associated production, for a total purchase price of $22.6 million, composed of cash and assumed liabilities. The purchase price for the acquisition has preliminarily been allocated as $6.7 million to proved oil and gas properties and $15.9 million to unproved oil and gas properties, pending the final closing.
March 2017 Acquisition
In March 2017, we closed an acquisition comprised primarily of developed and undeveloped oil and gas leasehold interests for a total purchase price of $25.1 million, composed of cash and assumed liabilities. The purchase price has been allocated as $15.3 million to proved oil and gas properties, $9.4 million to unproved oil and gas properties, and $0.4 million to other assets and land.
Acquisitions in the Second Half of 2016
In August and October 2016, the Company completed four acquisitions of certain assets for a total purchase price of $13.5 million composed of cash, forgiven receivables, and assumed liabilities. The acquired properties were comprised primarily of undeveloped oil and gas leasehold interests and additional interests in developed properties operated by the Company.
June 2016 Acquisition
In May 2016, we entered into a purchase and sale agreement 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 project in the Wattenberg Field for $505 million (the "GC Acquisition").
In June 2016, the Company closed on the portion of the assets comprised of undeveloped oil and gas leasehold interests and non-operated production. The effective date of this part of the transaction was April 1, 2016. As discussed above in "- September 2017 Acquisition" above, we closed on the second part of this transaction covering the operated producing properties in September 2017.
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) 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, 2017, the results of operations of the acquired assets, representing approximately $5.4 million of revenue and $4.7 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 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. See Note 9 for further details as to the preparation of these significant estimates.
Divestitures
During the year ended December 31, 2017, we completed divestitures of approximately 16,000 net undeveloped acres, along with associated production, outside of the Company's core development area for approximately $91.6 million in cash and the assumption by the buyers of $5.2 million in asset retirement obligations and $22.2 million in other liabilities.
During the year ended December 31, 2016, the Company completed divestitures of 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. The divested assets had associated production of approximately 200 BOED.
In accordance with full cost accounting guidelines, the net proceeds from these divestitures were credited to the full cost pool.
4.
Depletion, depreciation, and accretion ("DD&A")
DD&A 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, 2017, production of 12,481 MBOE represented 5.2% of estimated total proved reverses. For the year ended December 31, 2016, production of 4,271 MBOE represented 4.4% of estimated total proved reserves. 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. DD&A expense was $9.00 per BOE and $10.93 per BOE for the years ended December 31, 2017 and 2016, respectively. DD&A expense was $14.22 per BOE and $20.62 per BOE for the four months ended December 31, 2015 and the year ended August 31, 2015, 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, 2017, the Company decreased its asset retirement obligation by $0.2 million due to a revision to the expected timing of the future cash flows. During the year ended December 31, 2016, the Company increased its asset retirement obligation by $3.7 million due primarily 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 (sometimes referred to as the "Revolver") 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, 2017, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation of $400 million. As of December 31, 2017 and 2016, there was no outstanding principal balance. The Company has an outstanding letter of credit of approximately $0.5 million.
In September 2017, the lenders under the Revolver completed their regular semi-annual redetermination of our borrowing base. The borrowing base was increased from $225 million to $400 million. The next semi-annual redetermination is scheduled for April 2018.
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 years ended December 31, 2017 and 2016, was 3.4%, and 2.6%, 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 undertaken.
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. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the end of any fiscal quarter; 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, 2017, 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.
7.
Notes Payable
2025 Senior Notes
In November 2017, the Company issued $550 million aggregate principal amount of 6.25% Senior Notes (the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 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 2025 Senior Notes were $538.1 million after deductions of $11.9 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 6.6%. The net proceeds were used to fund the GCII Acquisition as discussed further in Note 3, repay the 2021 Senior Notes, and pay off the outstanding Revolver balance.
At any time prior to December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to 100% of the principal amount plus an Applicable Premium (as defined in the Indenture) plus accrued and unpaid interest. On and after December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to a specified percentage of the principal amount of the redeemed notes (104.688% for 2020, 103.125% for 2021, 101.563% for 2022, and 100% for 2023 and thereafter, during the twelve-month period beginning on December 1 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 1, 2020, the Company can, on one or more occasions, redeem up to 35% of the principal amount of the 2025 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 106.25% 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, 2017, 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.
2021 Senior Notes
In June 2016, the Company issued $80 million aggregate principal amount of 9% Senior Notes due 2021 (the "2021 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal was June 13, 2021. Interest on the 2021 Senior Notes accrued at 9% and began accruing on June 14, 2016. Interest was payable on June 15 and December 15 of each year, beginning on December 15, 2016. The 2021 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 2021 Senior Notes were $75.2 million after deductions of $4.8 million for expenses and underwriting discounts and commissions.
In December 2017, the Company repurchased all $80 million aggregate principal amount of the 2021 Senior Notes. At the time of repurchase, the Company made a required make whole payment of $8.2 million and wrote-off deferred issuance costs of $3.6 million.
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.
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 the cost of the put is offset by the proceeds of the call. 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 five counterparties and an exchange. Three 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 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 it 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, 2017 are summarized below:
Subsequent to December 31, 2017, the Company added the following positions:
Offsetting of Derivative Assets and Liabilities
As of December 31, 2017 and 2016, 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 the election of either party, 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, each party has 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 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 net of 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, 2017, three of the six 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 fourth counterparty, which
is not a lender under the credit facility, is unsecured and does not require the posting of collateral. The agreement with the fifth counterparty, which is not a lender under the credit facility, may require the posting of collateral if in a liability position. The agreement with the sixth 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 and certain asset acquisitions. Please refer to Notes 2, 3, and 5 for further discussion of unproved properties, business combinations and asset acquisitions, 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 and certain asset acquisitions requires fair value estimates for assets acquired and liabilities assumed. The fair value of assets and liabilities acquired is calculated using a net discounted cash flow approach for the proved producing, proved undeveloped, probable, and possible 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 market comparables.
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 Notes 3 and 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 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, 2017, derivative instruments utilized by the Company consist of 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 traded with third-party counterparties. 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, cash held in escrow, 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 $564.1 million at December 31, 2017. The Company determined the fair value of its notes payable at December 31, 2017 by using observable market based information for debt instruments of similar amounts and duration. The Company has classified the notes payable 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.
Shares of the Company’s common stock were issued during the years ended December 31, 2017 and 2016, the four months ended December 31, 2015, and the year ended August 31, 2015, as described further below.
Sales of common stock
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 November 2017, the Company, in connection with a registered underwritten public offering of its common stock (the “Offering”), entered into an underwriting agreement (the “Underwriting Agreement”) with the several underwriters named therein (the “Underwriters”) and pursuant to which the Company agreed to sell 35,000,000 shares of its common stock to the Underwriters at a price of $7.76 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 5,250,000 shares of common stock on the same terms and conditions. The option was exercised in full on November 10, 2017, bringing the total number of shares issued in the Offering to 40,250,000. Net proceeds to the Company, after deduction of underwriting discounts and expenses payable by the Company, were $312.2 million. The Company used the proceeds of the Offering to pay a portion of the purchase price of the GCII Acquisition, to repay a portion of the 2021 Senior Notes, and to repay amounts borrowed under the Revolver.
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.
12. Weighted-Average Shares Outstanding
The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share:
The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted 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, 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 period"). 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. As of December 31, 2017, there were 4,500,000 common shares authorized for
grant under the 2015 Equity Incentive Plan, of which 110,158 shares were available for future grants. The shares available for future grant exclude 951,884 shares which have been reserved for future vesting of performance-vested stock units in the event that these awards met the criterion to vest at their maximum multiplier.
The amount of stock-based compensation was as follows (in thousands):
Stock options
No stock options were granted during the year ended December 31, 2017. During the periods presented, 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, 2017:
The estimated unrecognized compensation cost from stock options not vested as of December 31, 2017, which will be recognized ratably over the remaining vesting period, is as follows:
Restricted stock units and stock bonus awards
The Company grants 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, 2017, which will be recognized ratably over the remaining vesting period, is as follows:
Performance-vested stock units
The Company grants 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, and the volatilities for each of the Company’s peers.
The assumptions used in valuing the PSUs granted were as follows:
The fair value of the PSUs granted during the years ended December 31, 2017 and 2016 was $5.1 million and $4.0 million, respectively. As of December 31, 2017, unrecognized compensation for PSUs was $5.0 million and will be amortized through 2019. 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 (the "plan") for eligible employees. Effective January 1, 2017, the Company modified the plan to include a discretionary matching contribution equal to 100% of compensation deferrals not to exceed 6% of eligible compensation. The Company contributed approximately $0.7 million for year ended December 31, 2017, $0.4 million for the year ended December 31, 2016, $0.1 million for the four months ended December 31, 2015, and $0.1 million during the year ended August 31, 2015 to the plan.
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):
On December 22, 2017, Congress signed Public Law No. 115-97, commonly referred to as the Tax Cut and Jobs Act of 2017 (“TCJA”). The passage of this legislation resulted in the change in the U.S. statutory rate from 35% to 21% beginning in January of 2018, the elimination of the corporate alternative minimum tax (“AMT”), the acceleration of depreciation for US tax purposes, limitations on deductibility of interest expense, the elimination of net operating loss carrybacks, and limitations on the use of future losses. In accordance with ASC 740, Income Taxes, the impact of a change in tax law is recorded in the period of enactment. Consequently, the Company has recorded a decrease to its net deferred tax assets of $24.0 million with a corresponding net adjustment to the valuation allowance for the year ended December 31, 2017. The Company also eliminated the $0.1 million deferred tax asset for its AMT credits and recorded a non-current tax receivable with a corresponding benefit to current income taxes. Based on the Company's current interpretation and subject to the release of the related regulations and any future interpretive guidance, the Company believes the effects of the change in tax law incorporated herein are substantially complete. As a result of other changes introduced by the TCJA, starting with compensation paid in 2018, Section 162(m) may limit us from deducting compensation, including performance-based compensation, in excess of $1 million paid to anyone who, starting in 2018, serves as the Chief Executive Officer or Chief Financial Officer, or who is among the three most highly compensated executive officers for any fiscal year. The only exception to this rule is for compensation that is paid pursuant to a binding contract in effect on November 2, 2017 that would have otherwise been deductible under the prior Section 162(m) rules. Accordingly, any compensation
paid in the future pursuant to new compensation arrangements entered into after November 2, 2017, even if performance-based, will count towards the $1 million fiscal year deduction limit if paid to a covered executive. Additional information that may affect our income tax accounts and disclosures would include further clarification and guidance on how the Internal Revenue Service will implement tax reform, including guidance with respect to 100% bonus depreciation on self-constructed assets and Section 162(m), further clarification and guidance on how state taxing authorities will implement tax reform and the related effect on our state income tax returns, completion of our 2017 tax return filings, and the potential for additional guidance from the SEC or the FASB related to tax reform.
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):
In connection with ASU 2016-09, deferred tax assets were increased by $4.5 million related to excess benefit net operating loss carryforwards along with a $4.5 million offsetting increase in the Company's valuation allowance. The impact of the adjustments netted to zero within retained earnings.
At December 31, 2017, the Company has U.S. Federal and state net operating loss carryforward of approximately $175.5 million that could be utilized to offset taxable income of future years. These net operating loss carryforwards will expire in various years beginning in 2025 with substantially all of the carryforwards expiring beginning in 2031.
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, 2017, 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.
The Company underwent an ownership change as defined in Section 382 of the Internal Revenue Code on December 31, 2016, as a result of our issuance of common stock. The amount of our taxable income for tax years ending after our ownership change, which may be offset by NOL carryovers from pre-change years, will be subject to an annual limitation, known as a Section 382 limitation. The Section 382 limitation is based on the value of our stock immediately before the ownership change multiplied by the long-term tax exempt rate in effect at the time of the ownership change, increased by built in gains recognized during the 5-year period beginning on the ownership change date. The identified change of ownership is not anticipated to restrict the Company's ability to utilize its NOLs.
As of December 31, 2017, 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. The Company's federal and state tax returns filed since August 31, 2014 and August 31, 2013, respectively, remain subject to examination by tax authorities.
16.
Other Commitments and Contingencies
Volume Commitments
The Company entered into firm sales agreements for its oil production with three counterparties during 2014 and entered into an additional firm sales agreement for its oil production in the third quarter 2017. Deliveries under two of the sales agreements commenced during 2015. Deliveries under the third agreement commenced in 2016. Deliveries under the fourth agreement are expected to commence in the fourth quarter of 2018. Pursuant to these agreements, we must deliver specific amounts of oil either from our own production or from oil 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 below, are as follows:
During the years ended December 31, 2017 and 2016, and four months ended December 31, 2015, the Company incurred transportation deficiency charges of $0.7 million, $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 year ended August 31, 2015.
In collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin. The first agreement includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed during the third quarter of 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. The second agreement also includes a new 200 MMcf per day processing plant as well as the expansion of a related gathering system. Both are currently expected to be completed in mid-2019, although the start-up date is undetermined at this time. Our share of the commitment will require 43.8 MMcf per day to be delivered after the plant in-service date for a period of 7 years. These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment. We expect that our development plan will support the utilization of this capacity.
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.
Office Leases
In September 2016, the Company entered into a new 65-month lease for the Company’s principal office space located in Denver, which commenced in the first quarter of 2017. 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.
Rent expense for office leases was $1.1 million for the year ended December 31, 2017, $1.0 million for year ended December 31, 2016, $0.3 million for the four months ended December 31, 2015, and $0.3 million for the year ended August 31, 2015.
Vehicle Leases
In December 2017, the Company entered into a leasing arrangement for its vehicles used in our normal operations. These leases expire after four years and are classified as capital leases. The assets associated with these capital leases are recorded within "Other property and equipment, net."
A schedule of the minimum lease payments under non-cancelable capital and operating leases as of December 31, 2017 follows (in thousands):
* Reflected in the balance sheet as current and non-current obligations of $63 thousand and $110 thousand, respectively, within "Accounts payable and accrued expenses" and "Other liabilities," respectively.
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 applicable SEC rules. Proved oil and natural gas reserves are calculated based on the prices for oil and natural gas during the twelve-month period before the determination date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period. 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 generally 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 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, 2017 included:
•
Purchases of reserves in place. For the year ended December 31, 2017, purchases of reserves in place of 45,103 MBOE were primarily attributable to the acquisition of proved reserves in the GCII Acquisition. Please see Note 3 for further information.
•
Revision of previous estimates. For the year ended December 31, 2017, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 14,581 MBOE primarily as a result of updated pricing as well as shifting from reporting reserves on a 2-stream to a 3-stream basis.
•
Extensions and discoveries. For the year ended December 31, 2017, total extensions and discoveries of 87,535 MBOE were primarily attributable to extending our development plan by a year due to the passage of time, the addition of a third rig for the second and third years of our development plan, and the drilling and completion of wells not previously proved.
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 GC Acquisition and related changes to our development plan that resulted in the removal of certain legacy PUD locations from 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. 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 was changed to remove undeveloped reserves that were not projected to be drilled in the subsequent 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. 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 vertical exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations.
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, 2017 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, 2017 through December 31, 2017. The December 31, 2017 oil price of $46.57 per barrel (West Texas Intermediate Cushing) was $10.50 higher than the December 31, 2016 oil price of $36.07 per barrel. The December 31, 2017 natural gas price of $2.21 per Mcf (Henry Hub) was $0.23 lower than the December 31, 2016 price of $2.44 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 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.
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 21st day of February 2018.
SRC Energy Inc.
/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, Mcf of natural gas by converting each six Mcf of natural gas to one Bbl of oil, and Bbls of NGLs.
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, and NGLs or 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.