VANCOUVER, BRITISH COLUMBIA--(Marketwired - Sept. 28, 2015) - Lynden Energy Corp. (TSX VENTURE:LVL) (the "Company") reports financial and operating results, and reserves, for the year ended June 30, 2015. This press release should be read in conjunction with the Company's Annual Report on Form 10-K for the year ended June 30, 2015 (the "Form 10-K") filed today with the Securities and Exchange Commission ("SEC") and Canadian Securities Regulators. All monetary references in this press release are to U.S. dollars.
Highlights
The Company's financial and operating performance for the year ended June 30, 2015 included the following highlights:
- The total number of producing Wolfberry wells increased from 91 gross (37.18 net) to 109 gross (44.69 net);
- Primarily as a result of a significant drop in commodity prices, petroleum and natural gas sales decreased by 25% as compared to the year ended June 30, 2014;
- Realized prices decreased 34% per Bbl of oil, 25% per Mcf of gas and 31% per Bbl of NGL compared to the year ended June 30, 2014; and
- Average daily production was 1,400 Boe/d in the year ended June 30, 2015 compared to 1,231 Boe/d in the year ended June 30, 2014, an increase of 20%.
Results of Operations
Net loss for the year ended June 30, 2015 was $565,153 and $0.00 per share and diluted share, compared to net income of $15,403,651 and $0.12 per share and diluted share for the year ended June 30, 2014. The $15,968,804 decrease in net income is primarily due to declining oil and gas revenues which were lower by $7,207,097 in 2015. In addition, there was no gain on disposition of property, plant and equipment in the year ended June 30, 2015 compared to a gain of $10,219,755 in the year ended June 30, 2014; depletion, depreciation and accretion was higher by $2,315,502; and production and operating expenses were higher by $1,319,810, which was offset by lower income taxes of $8,933,421.
Petroleum and Natural Gas Revenues
Oil revenues decreased 26% from $23,570,733 for the year ended June 30, 2014 to $17,367,615 for the year ended June 30, 2015 as a result of a $32.35 per Bbl decrease in our average realized price of oil only partially offset by an increase in oil production volumes of 28,422 Bbls. Natural gas revenues decreased 1% from $2,212,065 for the year ended June 30, 2014 to $2,198,265 for the year ended June 30, 2015 as a result of a $1.07 per Mcf decrease in our average realized natural gas price partially offset by an increase in natural gas production volumes of 170,857 Mcf. NGL revenues decreased 28% from $3,583,797 for the year ended June 30, 2014 to $2,593,618 for the year ended June 30, 2015 as a result of a $9.50 per Bbl decrease in our average realized NGL price partially offset by an increase in NGL production volumes of 5,026 Bbls. The following chart summarizes the Company's petroleum and natural gas revenues and production for the years ended June 30, 2015 and 2014.
| Year Ended June 30, |
|||||||||||||||||
| 2015 | 2014 | Change | % Change | ||||||||||||||
| Revenues | |||||||||||||||||
| Oil | $ | 17,367,615 | $ | 23,570,733 | $ | (6,203,118 | ) | (26%) | |||||||||
| Natural gas | 2,198,265 | 2,212,065 | (13,800 | ) | (1%) | ||||||||||||
| NGL | 2,593,618 | 3,583,797 | (990,179 | ) | (28%) | ||||||||||||
| Total revenues | $22,159,498 | $29,366,595 | $(7,207,097 | ) | (25%) | ||||||||||||
| Production | |||||||||||||||||
| Oil (Bbl) | 275,575 | 247,153 | 28,422 | 11 | % | ||||||||||||
| Natural gas (Mcf) | 689,594 | 518,737 | 170,857 | 33 | % | ||||||||||||
| NGL (Bbl) | 120,644 | 115,618 | 5,026 | 4 | % | ||||||||||||
| Total barrel of oil equivalent (Boe/d) | 511,151 | 449,228 | 61,923 | 14 | % | ||||||||||||
| Daily Production Averages | |||||||||||||||||
| Oil (Bbls/d) | 755 | 677 | 78 | 11 | % | ||||||||||||
| Natural gas (Mcf/d) | 1,889 | 1,421 | 468 | 28 | % | ||||||||||||
| NGL (Bbls/d) | 331 | 317 | 14 | 34 | % | ||||||||||||
| Total barrel of oil equivalent (Boe/d) | 1,400 | 1,231 | 169 | 20 | % | ||||||||||||
| Average Prices | |||||||||||||||||
| Oil (per Bbl) | $ | 63.02 | $ | 95.37 | $ | (32.35 | ) | (34 | %) | ||||||||
| Natural gas (per Mcf) | $ | 3.19 | $ | 4.26 | $ | (1.07 | ) | (25 | %) | ||||||||
| NGL (per Bbl) | $ | 21.50 | $ | 31.00 | $ | (9.50 | ) | (31 | %) | ||||||||
| Total barrel of oil equivalent (per Boe) | $ | 43.40 | $ | 65.37 | $ | (21.97 | ) | (34 | %) | ||||||||
Capital Requirements and Sources of Liquidity
The Company's primary sources of liquidity have been available cash on hand, cash generated from operations, borrowings under our Credit Facility, and proceeds from asset dispositions. To date, the Company's primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties.
Our fiscal 2015 (July 1, 2014 to June 30, 2015) capital budget for drilling, completion, recompletion and infrastructure was established at approximately $34 million.
During the year ended June 30, 2015, we spent approximately $29.1 million on capital expenditures on property, plant and equipment. Included in our fiscal 2015 capital budget were 1 gross horizontal Midland Basin well and 1 gross vertical Midland Basin well that were not spud by June 30, 2015 and are now incorporated in the fiscal 2016 capital budget. One horizontal Wolcott Lease well included in the fiscal 2015 capital budget was not drilled and has not been rescheduled.
Our fiscal 2016 (July 1, 2015 to June 30, 2016) capital budget for drilling, completion, recompletion and infrastructure is approximately $18.9 million, for the following:
- $6.0 million, or 32%, for the participation in the drilling and completion of 8 gross (3.25) net) Midland Basin vertical Wolfberry wells. Our fiscal 2016 budget contemplates a gross cost of a Wolfberry well of $1.6 million. Pursuant to the terms of our Midland Basin Participation Agreement our funding amount for the 3.25 net wells is equivalent to 3.71 wells;
- $11.2 million, or 59% for the participation in the drilling and completion of 3 gross horizontal Midland Basin wells in Glasscock County. The first well has been budgeted at a gross cost of $8.3 million, with the balance of wells budgeted at a gross cost of $7.0 million. Well design, in particular well length and completion approach, will be significant variables in the cost of these wells. The first of these wells has now been drilled and the remaining wells are not scheduled to be spud until June 2016. Pursuant to the terms of our Midland Basin Participation Agreement, the Company is funding 50% of the cost of the wells; and
- $1.7 million, or 9%, for the participation in the drilling and completion of 3 gross (1.5 net) vertical Mitchell Ranch Project wells. The gross cost of the first of the three wells is expected to be $1.4 million, with subsequent wells expected to be $1.0 million. The Company is funding 50% of the cost of the wells.
Based upon current oil and natural gas price expectations for fiscal 2016, we believe that our cash and cash equivalents on hand, our cash flow from operations and additional borrowings under our Credit Facility will provide us with sufficient liquidity to execute our current capital program excluding the two horizontal wells scheduled to be spud in June 2016 and any acquisitions we may enter into. The Company is not contractually bound to drill any wells to which it has not first consented.
Our Credit Facility is a reducing revolving line of credit of up to $100 million. The Credit Facility has a borrowing base of $37.5 million, of which $29.75 million was drawn down at June 30, 2015. As of September 28, 2015 $37.0 million has been drawn down on the Credit Facility. The bank's next engineering valuation of the Company's oil and gas reserves and re-determination of the borrowing base is anticipated to be completed in October 2015. Our cash balances totaled $8,748,008 at June 30, 2015.
Hedging
In April 2015, we entered into a NYMEX-based oil price put contract for 9,000 bbls of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per bbl as a hedge against some of the effects of commodity volatility during the period of the contract.
Current Production Levels
The Company's wells are currently producing approximately 1,450 Boe/d. Included in this production volume is production from the Mallard 23 #1H and McDaniel 2413 #1H wells, the Company's first two horizontal wells on the Wind Farms lease block in Glasscock County. The Mallard 23 #1H well has a lateral length of approximately 6,900 feet, and was completed with 35 individual frac stages. Gross production at the wellhead has averaged 477 barrels of oil and 242 Mcf of natural gas in the first 35 days of oil production. As part of the completion design of the well, production is currently being assisted with a gas lift. It is interpreted that the well may not have yet reached its peak 30 day production rate. The Company advises that although the initial rates from the Mallard 23 #1H well are encouraging, early production results are not necessarily indicative of the long-term performance or of ultimate recovery from these wells and longer term data is needed to more fully evaluate the impact on ultimate recovery. The McDaniel 2413 #1H well has a lateral length of approximately 9,500 feet and was completed with 48 individual frac stages, and is in the early stages of flowback. The Company has an approximately 43.7% working interest in both wells.
Summary Reserve Information
The following chart details our summary reserve information as of June 30, 2015. The information is based on a reserve report prepared by our independent consulting petroleum engineers, Cawley, Gillespie and Associates, Inc. ("CGA"), and prepared in accordance with the rules and regulations of the SEC.
| 12-Month Unweighted Average Pricing: Oil $71.68, Natural Gas $3.361 |
|||||||
| Oil (Mbbl) | Natural Gas (MMcf) | Natural Gas Liquids (Mbbl) | |||||
| Proved developed producing | 1,893.0 | 6,254.8 | 1,117.0 | ||||
| Proved developed non-producing | 333.8 | 468.3 | 83.6 | ||||
| Proved undeveloped | 4,402.5 | 12,848.2 | 2,284.5 | ||||
| Total proved | 6,629.3 | 19,571.3 | 3,485.1 | ||||
| Probable | 34.8 | 123.0 | 21.9 | ||||
Oil and Natural Gas Reserves under Canadian Law
As a reporting issuer under Alberta, British Columbia and Ontario securities laws, the Company is required under Canadian law to comply with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" ("NI 51-101") implemented by the members of the Canadian Securities Administrators in all of our reserves related disclosures. CGA evaluated the Company's reserves as of June 30, 2015, in accordance with the reserves definitions of NI 51-101 and the Canadian Oil and Gas Evaluators Handbook ("COGEH"). The Company's annual oil and natural gas reserves disclosures prepared in accordance with NI 51-101 and COGEH were filed today in Canada and are available under Lynden's profile at www.sedar.com.
About Lynden
Lynden Energy Corp. is in the business of acquiring, exploring and developing petroleum and natural gas rights and properties. The Company has various working interests in the Midland Basin and Eastern Shelf of the Permian Basin, West Texas, USA.
Further information relating to Lynden is also available on its website at www.lyndenenergy.com.
Units of equivalency
This press release uses oil equivalents (Boe) to express quantities of natural gas, natural gas liquids and oil in a common unit. A conversion ratio of 6 Mcf of natural gas to 1 barrel of oil is used. Boe may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Forward-looking statements
Certain statements and information in this press release may constitute "forward-looking statements" and are made pursuant to the "safe harbour" provisions of applicable Canadian securities laws and of the Private Securities Litigation Reform Act of 1995. The words "believe," "expect," "anticipate," "plan," "intend," "foresee," "should," "would," "could" or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on management's current expectations and beliefs concerning future developments and their potential effect on the Company. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those anticipated. All comments concerning expectations for future revenues and operating results are based on management's forecasts for the Company's existing operations and do not include the potential impact of any future acquisitions. Forward-looking statements involve significant risks and uncertainties (some of which are beyond the Company's control) and assumptions that could cause actual results to differ materially from the Company's historical experience and management's present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to: the volatility of commodity prices, product supply and demand; competition; access to and cost of capital; uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future; the assumptions underlying production forecasts; the quality of technical data; environmental and weather risks, including the possible impacts of climate change; the ability to obtain environmental and other permits and the timing thereof; government regulation or action; the costs and results of drilling and operations; the availability of equipment, services, resources and personnel required to complete the Company's operating activities; access to and availability of transportation, processing and refining facilities; the financial strength of counterparties to the Company's credit facility and the purchasers of the Company's production; and acts of war or terrorism; general economic conditions and other financial, operational and legal risks and uncertainties detailed from time to time in the Company's Securities and Exchange Commission filings.
For additional information regarding known material factors that could cause actual results to differ from projected results, please see "Part I, Item 1A. Risk Factors" in the Company's Form 10-K filed with the SEC on September 28, 2015, and which is also available under its profile at the SEDAR website (www.sedar.com), and with other reports that the Company files with the SEC and with Canadian securities regulators. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise, except as may be required by Canadian securities laws.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
Contact Information:
President and CEO
604-629-2991