Spartan Energy Corp.
TSX : SPE

Spartan Energy Corp.

November 09, 2016 08:00 ET

Spartan Energy Corp. Announces Third Quarter Financial and Operating Results

CALGARY, ALBERTA--(Marketwired - Nov. 9, 2016) - Spartan Energy Corp. ("Spartan" or the "Company") (TSX:SPE) is pleased to report its financial and operating results for the three and nine months ended September 30, 2016. Selected financial and operational information is set out below and should be read in conjunction with Spartan's September 30, 2016 interim financial statements and the related management's discussion and analysis, which are available for review at www.sedar.com or on the Company's website at www.spartanenergy.ca.

THIRD QUARTER FINANCIAL AND OPERATIONAL HIGHLIGHTS

Spartan's highlights for the third quarter include:

  • Achieved record average production of 12,429 boe/d (91% oil and liquids), representing a 55% percent increase over the third quarter of 2015 and a 37% increase over the second quarter of 2016. Spartan exceeded our year-end production target of 12,500 boe/d prior to the end of the third quarter.
  • Completed the acquisition of light oil assets in southeast Saskatchewan producing approximately 450 boe/d for a cash purchase price of approximately $24 million. To date in 2016, Spartan has completed four consolidating acquisitions in our core southeast Saskatchewan operating area, representing approximately 3,430 boe/d of production, for an aggregate purchase price of $172.2 million.
  • Completed a bought-deal equity financing of 25,415,000 common shares at a price of $3.18 per common share for gross proceeds of approximately $80.8 million.
  • Drilled 26 (22.4 net) wells in the quarter and brought 21 (19.2 net) wells on production.
  • Continued to reduce drilling costs, with drill, complete and equip ("DC&E") costs for single leg open-hole horizontal wells drilled after the first quarter averaging approximately $600,000.
  • Reduced net general and administrative ("G&A") costs to $1.63 per boe in the third quarter, a reduction of 27% from the second quarter of 2016 and 16% from the third quarter of 2015.
  • Realized an operating netback of $19.05 per boe, resulting in quarterly funds flow from operations of $18.9 million ($0.06 per basic share and $0.05 per diluted share).
  • Maintained our balance sheet strength, with net debt at the end of the quarter (excluding finance lease obligations) of approximately $49 million and available liquidity of approximately $101 million.

FINANCIAL RESULTS

(Cdn$000s except per boe and per share amounts) Three Months Ended
September 30
Nine Months Ended
September 30
2016 2015 2016 2015
Average daily production (boe/d) 12,429 8,042 10,403 8,712
Net realized oil and gas sales price (excluding derivatives) ($/boe) 44.20 47.40 40.25 49.43
Royalties ($/boe)(2) 6.83 7.67 6.04 7.74
Production costs ($/boe)(1) 18.28 17.44 16.23 17.49
Operating netback ($/boe)(3) 19.05 22.29 17.96 24.20
Net general and administrative expenses ($/boe) 1.63 1.93 1.92 2.09
Interest expense ($/boe) 0.86 0.97 0.68 1.03
Funds flow from operations(3)(4) 18,922 14,341 43,791 50,122
per share - basic 0.06 0.05 0.14 0.19
per share - diluted 0.05 0.05 0.13 0.17
Net income (loss) (5) 4,102 (33,388) (15,438) (51,658)
per share - basic 0.01 (0.13) (0.05) (0.20)
per share - diluted 0.01 (0.13) (0.05) (0.20)
Capital expenditures(6) 20,780 19,376 44,766 48,936
Net debt(3) 81,271 86,884 81,271 86,884
Net debt exclusive of finance lease obligations(3) 48,954 86,884 48,954 86,884
Bank Facility 150,000 150,000 150,000 150,000
Weighted average shares outstanding
basic 329,938,297 264,277,846 303,110,506 264,270,046
diluted 356,147,715 285,637,309 327,634,815 286,853,924
  1. Including transportation costs.
  2. Royalties include Saskatchewan resource surcharge.
  3. Funds flow from operations, operating netback, net debt and net debt exclusive of finance lease obligations are non-IFRS measures. See "Non-IFRS Measures".
  4. Excluding transaction costs.
  5. Net loss for the three and nine months ended September 30, 2015 includes a non-cash impairment charge of $34 million in Spartan's Alberta-Alexander and West Central Saskatchewan - Viking CGUs due to lower forecasted prices for oil and natural gas. This non-cash charge has no impact on the Company's cash flow or credit facilities and the impairment charges can be reversed in future periods if commodity prices increase. Net income for the three and nine months ended September 30, 2016 includes a gain of $12.6 million on Spartan's Midale acquisition, completed in the third quarter of 2016, as the purchase price paid was determined to be less than the recorded fair values of the net assets acquired and liabilities assumed.
  6. Excluding acquisitions.

CORPORATE AND ACQUISITION UPDATE

Spartan's strategy in 2016 has focused on preserving liquidity through the depressed commodity price cycle by limiting capital spending to cash flow, while using our financial flexibility and strong cost of capital to deliver per share growth through accretive acquisitions. We continued to deliver on this strategy in the third quarter, successfully completing the acquisition of approximately 450 boe/d in southeast Saskatchewan for aggregate consideration of approximately $24 million. To date in 2016, Spartan has completed four accretive consolidating acquisitions in our core southeast Saskatchewan operating area, adding approximately 3,430 boe/d of production, 10.1 MMboe of proved developed producing ("PDP") reserves(1), 24.4 MMboe of proved plus probable reserves(1) and 314 net drilling locations.(2) The additional drilling locations supplement our inventory of open-hole locations in southeast Saskatchewan, which deliver some of the most economic returns in the Western Canadian Sedimentary Basin, as well as significantly expand our exposure to the frac Midale resource play in the Alameda and Pinto areas of southeast Saskatchewan.

Spartan's disciplined approach to asset valuation was reflected in the combined metrics associated with the acquisitions, as the aggregate purchase price represents $50,204 per flowing barrel of production, 6.2 times 12 month cash flow(3), $17.05 per boe of PDP reserves and $7.06 per boe of 2P reserves. The acquisitions increased our PDP reserves by 75%, our 2P reserves by 61% and our southeast Saskatchewan drilling location count by 37%. Accounting for the equity issuances used to finance the acquisitions, this was accomplished with a 30% increase to our outstanding share count while net debt was reduced by approximately $38 million. The assets purchased were also complementary to our existing asset base, resulting in minimal incremental G&A costs to Spartan. This resulted in net G&A costs for the third quarter of $1.63 per boe, a reduction of 27% from the second quarter of 2016.

In the third quarter Spartan also successfully completed a bought-deal equity financing of 25,415,000 common shares at a price of $3.18 per common share for gross proceeds of approximately $80.8 million, allowing us to maintain financial flexibility. At the end of the third quarter, our current net debt (excluding finance lease obligations) was approximately $49 million, representing 0.7x annualized third quarter cash flow, and we had approximately $101 million undrawn on our $150 million credit facility.

OPERATIONAL UPDATE

Operationally, our southeast Saskatchewan assets continue to exceed expectations. Following spring break-up, Spartan re-commenced drilling operations late in the second quarter and had two rigs actively drilling throughout the third quarter. We drilled 26 (22.4 net) development wells in the third quarter of 2016 and brought 21 (19.2 net) wells on production in the quarter. A summary of our drilling activity to date in 2016 is provided below.

2016 Drilling Program Development
Wells Spud
Development Well
On Production
Exploratory
Wells Spud
As at September 30, 2016 Gross Net Gross Net Gross Net
Southeast Saskatchewan - Conventional Mississippian 34 29.6 31 27.8 4 3.1
Southeast Saskatchewan - Frac Midale 11 8.5 7 5.0 - -
West Central Saskatchewan - Frac Viking - - 7 5.9 - -
Total 45 38.1 45 38.7 4 3.1

Our open-hole drilling program was focused in our core greater Queensdale and greater Winmore operating areas and included a number of wells designed to delineate pool boundaries and extensions at Winmore. On average, open-hole wells drilled following the completion of spring break-up again delivered initial thirty day production rates ("IP30") exceeding our internal unrisked type curve. The 31 total gross open-hole wells drilled and put on production to date in 2016 have delivered an IP30 rate of approximately 130 bbls/d, 19% above our unrisked Tier 1 type curve. The Tier 1 type well on Crown land delivers an internal rate of return in excess of 260% at US$50 WTI constant pricing and pays out in approximately 7 months.

In the third quarter, Spartan also commenced drilling frac Midale wells on our Alameda property, which we acquired pursuant to our purchase of Wyatt Oil & Gas Inc. ("Wyatt") in the second quarter of 2016. We drilled four net wells in the third quarter, none of which were on production prior to the end of the quarter, and we completed and brought on production one well that was drilled prior to the quarter. We plan to drill a total of 6 net wells and bring 7 net wells on production at Alameda in 2016. Results to date have been encouraging, with the first well placed on production delivering an IP30 oil rate of 243 bbls/d, significantly exceeding our budget type curve. Our third party gas processing facility at Alameda commenced operations late in the third quarter, allowing us to tie-in previously flared gas volumes in the area.

Spartan continued to work to reduce drilling costs in the third quarter. DC&E costs for our single leg open-hole wells in Southeast Saskatchewan drilled subsequent to the end of the first quarter of 2016 averaged approximately $600,000. These cost reductions serve to further improve the best in class returns of our open hole drilling locations and resulted in capital spending for the third quarter being below budgeted levels.

Operating and transportation costs increased to $18.23 per boe in the third quarter of 2016 due to the acquisition of higher operating cost properties and due to additional maintenance, well servicing and facility turnaround requirements in the quarter. Spartan had deferred well servicing projects and facility turnarounds to the second half of 2016 as commodity price weakness in the first quarter of 2016 rendered certain workover projects uneconomic and the spring break-up period in the second quarter of 2016 restricted lease access. As commodity prices improved in the third quarter, Spartan completed these projects and realized increased production levels as a result.

Operating costs also included significant maintenance expenditures and well servicing costs on the assets acquired by the Company in 2016. Insufficient maintenance capital had been allocated to the assets prior to their acquisition by Spartan as they were considered non-core by their vendors and projects had been halted during sale processes. Upon closing of the acquisitions, Spartan proactively identified and completed a number of workovers and reactivations. These workovers increased operating and transportation expenses in the third quarter but also contributed to an increase in base production. On the Corning-Manor acquired assets, Spartan added approximately 90 bbls/d as a result of workovers and reactivations completed in the quarter. Spartan is not expecting similar maintenance cost and workover requirements moving forward.

As part of the acquisition of Wyatt, Spartan assumed a commitment for minimum gas volumes to be delivered to a gas processing facility constructed at the Alameda oil battery. The facility was completed ahead of schedule and under budget and was commissioned for operations in August 2016. Spartan began incurring gas processing fees on the delivered gas volumes in September, which are included in operating and transportation expenses.

Spartan anticipates per boe operating costs to decrease over the next two quarters as workover and maintenance activity returns to normalized levels and our drilling program at Alameda increases gas volumes into the processing facility.

INCREASE TO 2016 GUIDANCE

Spartan continues to demonstrate the repeatability of our asset base, as our open-hole wells drilled following spring break-up are currently outperforming our internal type curve. The success of the drilling program, together with production additions from workovers and reactivations, resulted in third quarter production significantly outperforming our internal budget, and we exceeded our forecasted year-end exit production rate prior to the end of the third quarter. As a result of this success, we are revising our 2016 exit guidance from 12,500 boe/d to 13,500 boe/d and our average production guidance from 10,700 boe/d to 11,200 boe/d. As a result of realized savings in DC&E costs, we are also reducing our 2016 capital expenditure budget from $68 million to $66 million. Moving into 2017, we intend to continue our business plan of measured, sustainable growth by delivering 10 to 15 percent organic production growth within cash flow while seeking to provide further shareholder value through accretive acquisitions. We anticipate formalizing our 2017 guidance in late 2016 or early 2017 based on prevailing commodity prices at the time.

OUTLOOK

Spartan has maintained discipline over the past two years of depressed commodity prices, spending within cash flow, reducing costs and enhancing per share value through accretive acquisitions. Our acquisition activity has significantly added to our location inventory, and we now have over 970 net locations in southeast Saskatchewan providing a platform for multi-year organic production growth. We have also been disciplined in managing our balance sheet, with net debt (exclusive of finance lease obligations) at the end of the third quarter of approximately $49 million, representing 0.7x annualized third quarter cash flow, and $101 million available borrowing on our $150 million credit facility. This financial flexibility positions us to continue to supplement our growth by capitalizing on high quality, accretive acquisition opportunities.

READER ADVISORY AND FOOTNOTES

Footnotes:

  1. Gross Company Reserves. Reserves were prepared by GLJ Petroleum Consultants ("GLJ") and Sproule Associates Limited ("Sproule") effective December 31, 2015 using the GLJ and Sproule December 31, 2015 forecast prices and costs in accordance with National Instrument 51-101 - Standards of Disclosure of Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook (the "GLJ Report"). Gross Company Reserves means the company's working interest reserves before the calculation of royalties, and before the consideration of the company's royalty interests.
  2. Drilling inventory can be subdivided in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the the applicable independent engineering reports and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 314 net drilling locations identified in this press release, 78 are proved locations, 45 are probable locations and 191 are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
  3. Projected cash flows from operations, cash flow accretion and production accretion based on 12 month forecast production and cash flows from the date of acquisition using a US$50 WTI oil price and $0.76 Cdn/US FX, assuming cash flow from the applicable asset is reinvested in drilling during the period.

BOE Disclosure. The term barrels of oil equivalent ("BOE") may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per barrel (6mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All BOE conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

Forward-Looking Statements. Certain information included in this press release constitutes forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this press release may include, but is not limited to, planned drilling and completion activities, future production and capital spending levels, year-end debt levels and the completion of potential asset acquisitions.

The forward-looking statements contained in this press release are based on certain key expectations and assumptions made by Spartan, including expectations and assumptions concerning the success of future drilling, development and completion activities, the performance of existing wells, the performance of new wells, the availability and performance of facilities and pipelines, the geological characteristics of Spartan's properties, the successful application of drilling, completion and seismic technology, prevailing weather and break-up conditions, commodity prices, royalty regimes and exchange rates, the application of regulatory and licensing requirements, the availability of capital, labour and services, the creditworthiness of industry partners and the satisfaction of all conditions to the closing of the asset acquisitions.
Although Spartan believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Spartan can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), constraint in the availability of services, commodity price and exchange rate fluctuations, adverse weather or break-up conditions and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. These and other risks are set out in more detail in Spartan's Annual Information Form for the year ended December 31, 2015.

Forward-looking information is based on a number of factors and assumptions which have been used to develop such information but which may prove to be incorrect. Although Spartan believes that the expectations reflected in its forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because Spartan can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this press release, assumptions have been made regarding and are implicit in, among other things, the timely receipt of any required regulatory approvals (including Court and shareholder approvals) and the satisfaction of all conditions to the completion of the transaction. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used.

The forward-looking information contained in this press release is made as of the date hereof and Spartan undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward looking information contained in this press release is expressly qualified by this cautionary statement.

Non-IFRS Measures. This press release provides certain financial measures that do not have a standardized meaning prescribed by IFRS. These non-IFRS financial measures may not be comparable to similar measures presented by other issuers. Funds flow from operations, operating netback and net surplus (debt) are not recognized measures under IFRS. Management believes that in addition to net income (loss), funds flow from operations, operating netback and net surplus (debt) are useful supplemental measures that demonstrate the Company's ability to generate the cash necessary to repay debt or fund future capital investment. Investors are cautioned, however, that these measures should not be construed as an alternative to net income (loss) determined in accordance with IFRS as an indication of Spartan's performance. Spartan's method of calculating these measures may differ from other companies and accordingly, they may not be comparable to measures used by other companies. Cash flow from operations is calculated by adjusting net income (loss) for other income, unrealized gains or losses on financial derivative instruments, transaction costs, accretion, share based compensation, impairment and depletion and depreciation. Operating netback is calculated based on oil and gas revenue less royalties and operating expenses. Net surplus (debt) is the total of cash plus accounts receivable, prepaids and deposits, less accounts payable plus bank debt. Net debt has also been presented exclusive of finance lease obligations, as Spartan believes that such measure is useful to evaluate Spartan's financial liquidity.

Contact Information

  • Spartan Energy Corp.
    Richard (Rick) McHardy
    President and Chief Executive Officer

    Spartan Energy Corp.
    Tim Sweeney
    Manager, Business Development

    Spartan Energy Corp.
    Suite 500, 850 - 2nd Street S.W.
    Calgary, Alberta T2P 0R8
    403.355.2779 (FAX)
    info@spartanenergy.ca